Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbols	Name of exchange on which registered
Class A common stock, par value $0.01 per share	SPKE	The NASDAQ Global Select Market
8.75% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Stock, par value $0.01 per share	SPKEP	The NASDAQ Global Select Market

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•	changes in commodity prices;

•	the sufficiency of risk management and hedging policies and practices;

•	the impact of extreme and unpredictable weather conditions, including hurricanes and other natural disasters;

•	federal, state and local regulations, including the industry's ability to address or adapt to potentially restrictive new regulations that may be enacted by public utility commissions;

•	our ability to borrow funds and access credit markets;

•	restrictions in our debt agreements and collateral requirements;

•	credit risk with respect to suppliers and customers;

•	changes in costs to acquire customers as well as actual attrition rates;

•	accuracy of billing systems;

•	our ability to successfully identify, complete, and efficiently integrate acquisitions into our operations;

•	significant changes in, or new changes by, the independent system operators (“ISOs”) in the regions we operate;

•	competition; and

•	the “Risk Factors” in this Annual Report, and in our quarterly reports, other public filings and press releases.

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PART I.

Items 1 & 2. Business and Properties

General

We are an independent retail energy services company founded in 1999 and are organized as a Delaware corporation that provides residential and commercial customers in competitive markets across the United States with an alternative choice for their natural gas and electricity. We purchase our electricity and natural gas supply from a variety of wholesale providers and bill our customers monthly for the delivery of electricity and natural gas based on their consumption at either a fixed or variable price. Electricity and natural gas are then distributed to our customers by local regulated utility companies through their existing infrastructure.

Our business consists of two operating segments:

•	Retail Electricity Segment. In this segment, we purchase electricity supply through physical and financial transactions with market counterparties and ISOs and supply electricity to residential and commercial consumers pursuant to fixed-price and variable-price contracts.

•	Retail Natural Gas Segment. In this segment, we purchase natural gas supply through physical and financial transactions with market counterparties and supply natural gas to residential and commercial consumers pursuant to fixed-price and variable-price contracts.

Our Operations

As of December 31, 2019, we operated in 94 utility service territories across 19 states and the District of Columbia and had approximately 672,000 residential customer equivalents (“RCEs”). An RCE is an industry standard measure of natural gas or electricity usage with each RCE representing annual consumption of 100 MMBtu of natural gas or 10 MWh of electricity. We serve natural gas customers in fifteen states (Arizona, California, Colorado, Connecticut, Florida, Illinois, Indiana, Maryland, Massachusetts, Michigan, Nevada, New Jersey, New York, Ohio and Pennsylvania) and electricity customers in twelve states (Connecticut, Delaware, Illinois, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Ohio, Pennsylvania and Texas) and the District of Columbia using seven brands (Electricity Maine, Electricity N.H., Major Energy, Provider Power Mass, Respond Power, Spark Energy, and Verde Energy).

Customer Contracts and Product Offerings

Fixed and variable-price contracts

We offer a variety of fixed-price and variable-price service options to our natural gas and electricity customers. Under our fixed-price service options, our customers purchase natural gas and electricity at a fixed price over the life of the customer contract, which provides our customers with protection against increases in natural gas and electricity prices. Our fixed-price contracts typically have a term of one to two years for residential customers and up to three years for commercial customers, and most provide for an early termination fee in the event that the customer terminates service prior to the expiration of the contract term. In a typical market, we offer fixed-price electricity plans for 6, 12 and 24 months and fixed-price natural gas plans from 12 to 24 months, which may or may not provide for a monthly service fee and/or a termination fee, depending on the market and customer type. Our variable-price service options carry a month-to-month term and are priced based on our forecasts of underlying commodity prices and other market factors, including the competitive landscape in the market and the regulatory environment, and may also include a monthly service fee depending on the market and customer type. We also offer variable-price natural gas and electricity plans that offer an introductory fixed price that is generally applied for a certain number of billing cycles, typically two billing cycles in our current markets, then switches to a variable price based on market conditions. Our variable plans may or may not provide for a termination fee, depending on the market and customer type.

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The fixed/variable splits of our RCEs were as follows as of December 31, 2019:

Green products and renewable energy credits

We offer renewable and carbon neutral (“green”) products in certain markets. Green energy products are a growing market opportunity and typically provide increased unit margins as a result of improved customer satisfaction and less competition. Renewable electricity products allow customers to choose electricity sourced from wind, solar, hydroelectric and biofuel sources, through the purchase of renewable energy credits (“RECs”). Carbon neutral natural gas products give customers the option to reduce or eliminate the carbon footprint associated with their energy usage through the purchase of carbon offset credits. These products typically provide for fixed or variable prices and generally follow the terms of our other products with the added benefit of carbon reduction and reduced environmental impact. We currently offer renewable electricity in all of our electricity markets and carbon neutral natural gas in several of our gas markets. As of December 31, 2019, approximately 37% of our customers utilized green products.

In addition to the RECs we purchase to satisfy our voluntary requirements under the terms of our green contracts with our customers, we must also purchase a specified number of RECs based on the amount of electricity we sell in a state in a year pursuant to individual state renewable portfolio standards. We forecast the price for the required RECs at the end of each month and incorporate this cost component into our customer pricing models.

Customer Acquisition and Retention

Our customer acquisition strategy consists of customer growth obtained through traditional sales channels complemented by customer portfolio and business acquisitions. We make decisions on how best to deploy capital based on a variety of factors, including cost to acquire customers, availability of opportunities and our view of attractive commodity pricing in particular regions.

Organic Growth

We use organic sales strategies to both maintain and grow our customer base by offering competitive pricing, price certainty, and/or green product offerings. We manage growth on a market-by-market basis by developing price curves in each of the markets we serve and comparing the market prices to the price offered by the local regulated utility. We then determine if there is an opportunity in a particular market based on our ability to create a competitive product on economic terms that provides customer value and satisfies our profitability objectives. The attractiveness of a product from a consumer’s standpoint is based on a variety of factors, including overall pricing, price stability, contract term, sources of generation and environmental impact and whether or not the contract

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provides for termination and other fees. Product pricing is also based on several other factors, including the cost to acquire customers in the market, the competitive landscape and supply issues that may affect pricing.

Once a product has been created for a particular market, we then develop a marketing campaign using a combination of sales channels. We identify and acquire customers through a variety of sales channels, including our inbound customer care call center, outbound calling, online marketing, opt-in web-based leads, email, direct mail, door-to-door sales, affinity programs, direct sales, brokers and consultants. For residential customers, we primarily use indirect sales brokers, web based solicitation, door-to-door sales, outbound calling, and other methods. For 2019, the largest channels were outbound telemarketing, door-to-door sales, and web-based sales. For C&I customers, which are typically larger and have greater natural gas and electricity requirements, we typically use brokers or direct marketing to obtain these customers. At December 31, 2019, our customer base was 61% residential and 39% C&I customers. In our sales practices, we typically employ multiple vendors under short-term contracts and have not entered into any exclusive marketing arrangements with sales vendors. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve targeted growth and manage customer acquisition costs. We strive to maintain a disciplined approach to recovery of our customer acquisition costs within defined periods.

Acquisitions

We actively monitor acquisition opportunities that may arise in the domestic acquisition market, and seek to acquire both portfolios of customers as well as retail energy companies utilizing some combination of cash and borrowings under our Senior Credit Facility, the issuance of common or preferred stock, or other financing arrangements. Historically, our customer acquisition strategy has been executed using both third parties and through affiliated relationships. See “—Relationship with our Founder and Majority Shareholder” for a discussion of affiliate relationships.

The following table provides a summary of our acquisitions over the past five years:

	Company / Portfolio	Date Completed	RCEs	Segment	Acquisition Source
	Customer Portfolio	February 2015	12,500	Electricity	Third Party
	CenStar Energy Corp.	July 2015	65,000	Natural Gas Electricity	Third Party
	Oasis Power Holdings, LLC	July 2015	40,000	Natural Gas Electricity	Affiliate
	Customer Portfolio	September 2015	9,500	Natural Gas	Third Party
	Provider Companies (1)	August 2016	121,000	Electricity	Third Party
	Major Energy Companies (2)	August 2016	220,000	Natural Gas Electricity	Affiliate
	Perigee Energy, LLC	April 2017	17,000	Natural Gas Electricity	Affiliate
	Verde Companies (3)	July 2017	145,000	Electricity	Third Party
	Customer Portfolio	October 2017	44,000	Electricity	Third Party
	HIKO Energy, LLC	March 2018	29,000	Natural Gas Electricity	Third Party
	Customer Portfolio	December 2018	35,000	Natural Gas Electricity	Affiliate
	Customer Portfolio	May 2019	60,000	Natural Gas Electricity	Third Party

(1)	Included Electricity Maine, LLC, Electricity N.H., LLC, Provider Power Mass, LLC (collectively, the “Provider Companies”).

(2)	Included Major Energy Services, LLC, Major Energy Electric Services, LLC, and Respond Power, LLC (collectively, the “Major Energy Companies”).

(3)	Included Verde Energy USA, Inc.; Verde Energy USA Commodities, LLC; Verde Energy USA Connecticut, LLC; Verde Energy USA DC, LLC; Verde Energy USA Illinois, LLC; Verde Energy USA Maryland, LLC; Verde Energy USA Massachusetts, LLC; Verde Energy USA New Jersey, LLC; Verde

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Energy USA New York, LLC; Verde Energy USA Ohio, LLC; Verde Energy USA Pennsylvania, LLC; Verde Energy USA Texas Holdings, LLC; Verde Energy USA Trading, LLC; and Verde Energy Solutions, LLC (collectively, the “Verde Companies”).

Please see Item 9B. “Other Information” and Note 4 "Acquisitions" in the notes to our consolidated financial statements for a more detailed description of these acquisitions, including the purchase price, the source of funds and financing arrangements with our Founder and/or NG&E. Please see “Risk Factors" for a discussion of risks related to our acquisition strategy and ability to finance such transactions.

Retaining customers and maximizing customer lifetime value

Following the acquisition of a customer, we devote significant attention to customer retention. We have developed a disciplined renewal communication process, which is designed to effectively reach our customers prior to the end of the contract term, and employ a team dedicated to managing this renewal communications process. Customers are contacted in each utility prior to the expiration of the customer's contract. We may contact the customer through additional channels such as outbound calls or email. We also apply a proprietary evaluation and segmentation process to optimize value to both us and the customer. We analyze historical usage, attrition rates and consumer behaviors to specifically tailor competitive products that aim to maximize the total expected return from energy sales to a specific customer, which we refer to as customer lifetime value.

We actively monitor unit margins from energy sales. We use this information to assess the results of products and to guide business decisions, including whether to engage in pro-active non-renewal of lower margin customers is in the interest of the Company.

Investment in ESM

In 2016, we and eREX Co., Ltd., a Japanese company, entered into a joint venture investment in eREX Spark Marketing Co., Ltd ("ESM"). Operations for ESM began on April 1, 2016 in connection with the deregulation of the Japanese power market. As part of the agreement, we made contributions of 156.4 million Japanese Yen, or $1.4 million, for a 20% ownership interest in ESM.

In November 2019, Spark HoldCo, LLC entered into a share purchase agreement with eREX Co., Ltd. In accordance with the agreement, we sold our 20% ownership interest in ESM for $8.4 million. See Note 17 "Equity Method Investment" for further discussion.

Commodity Supply

We hedge and procure our energy requirements from various wholesale energy markets, including both physical and financial markets, through short- and long-term contracts. Our in-house energy supply team is responsible for managing our commodity positions (including energy procurement, capacity, transmission, renewable energy, and resource adequacy requirements) within our risk management policies. We procure our natural gas and electricity requirements at various trading hubs, city-gates and load zones. When we procure commodities at trading hubs, we are responsible for delivery to the applicable local regulated utility for distribution.

In most markets, we hedge our electricity exposure with financial products and then purchase the physical power directly from the ISO for delivery. Alternatively, we may use physical products to hedge our electricity exposure rather than buying physical electricity in the day-ahead market from the ISO. During the year ended December 31, 2019, we transacted physical and financial settlement of electricity with approximately 13 suppliers.

We are assessed monthly for ancillary charges such as reserves and capacity in the electricity sector by the ISOs. For example, the ISOs will charge all retail electricity providers for monthly reserves that the ISO determines are necessary to protect the integrity of the grid. We attempt to estimate such amounts, but they are difficult to estimate because they are charged in arrears by the ISOs and are subject to fluctuations based on weather and other market

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conditions. Many of the utilities we serve also allocate natural gas transportation and storage assets to us as a part of their competitive choice program. We are required to fill our allocated storage capacity with natural gas, which creates commodity supply and price risk. Sometimes we cannot hedge the volumes associated with these assets because they are too small compared to the much larger bulk transaction volumes required for trades in the wholesale market or it is not economically feasible to do so.

We periodically adjust our portfolio of purchase/sale contracts in the wholesale natural gas market based upon continual analysis of our forecasted load requirements. Natural gas is then delivered to the local regulated utility city-gate or other specified delivery point where the local regulated utility takes control of the natural gas and delivers it to individual customer locations. Additionally, we hedge our natural gas price exposure with financial products. During the year ended December 31, 2019, we transacted physical and financial settlements of natural gas with approximately 70 wholesale counterparties.

We also enter into back-to-back wholesale transactions to optimize our credit lines with third-party energy suppliers. With each of our third-party energy suppliers, we have certain contracted credit lines, within which we are able to purchase energy supply from these counterparties. If we desire to purchase supply beyond these credit limits, we are required to post collateral in the form of either cash or letters of credit. As we begin to approach the limits of our credit line with one supplier, we may purchase energy supply from another supplier and sell that supply to the original counterparty in order to reduce our net position with that counterparty and open up additional credit to procure supply in the future. Our sales of gas pursuant to these activities also enable us to optimize our credit lines with third-party energy suppliers by decreasing our net buy position with those suppliers.

Asset Optimization

Part of our business includes asset optimization activities in which we identify opportunities in the wholesale natural gas markets in conjunction with our retail procurement and hedging activities. Many of the competitive pipeline choice programs in which we participate require us and other retail energy suppliers to take assignment of and manage natural gas transportation and storage assets upstream of their respective city-gate delivery points. In our allocated storage assets, we are obligated to buy and inject gas in the summer season (April through October) and sell and withdraw gas during the winter season (November through March). These injection and purchase obligations require us to take a seasonal long position in natural gas. Our asset optimization group determines whether market conditions justify hedging these long positions through additional derivative transactions. We also contract with third parties for transportation and storage capacity in the wholesale market and are responsible for reservation and demand charges attributable to both our allocated and third-party contracted transportation and storage assets. Our asset optimization group utilizes these allocated and third-party transportation and storage assets in a variety of ways to either improve profitability or optimize supply-side counterparty credit lines.

We frequently enter into spot market transactions in which we purchase and sell natural gas at the same point or we purchase natural gas at one location and ship it using our pipeline capacity for sale at another location, if we are able to capture a margin. We view these spot market transactions as low risk because we enter into the buy and sell transactions on a back-to-back basis. We also act as an intermediary for market participants who need assistance with short-term procurement requirements. Consumers and suppliers contact us with a need for a certain quantity of natural gas to be bought or sold at a specific location. When this occurs, we are able to use our contacts in the wholesale market to source the requested supply and capture a margin in these transactions.

Our risk policies require that optimization activities be limited to back-to-back purchase and sale transactions, or open positions subject to aggregate net open position limits, which are not held for a period longer than two months. Furthermore, all additional capacity procured outside of a utility allocation of retail assets must be approved by a risk committee. Hedges of our firm transportation obligations are limited to two years or less and hedging of interruptible capacity is prohibited.

Risk Management

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We operate under a set of corporate risk policies and procedures relating to the purchase and sale of electricity and natural gas, general risk management and credit and collections functions. Our in-house energy supply team is responsible for managing our commodity positions (including energy, capacity, transmission, renewable energy, and resource adequacy requirements) within our risk management policies. We attempt to increase the predictability of cash flows by following our hedging strategies.

Our risk committee has control and authority over all of our risk management activities. The risk committee establishes and oversees the execution of our credit risk management policy and our commodity risk policy. The risk management policies are reviewed at least annually by the risk management committee and such committee typically meets quarterly to assure that we have followed these policies. The risk committee also seeks to ensure the application of our risk management policies to new products that we may offer. The risk committee is comprised of our Chief Executive Officer and our Chief Financial Officer, who meet on a regular basis to review the status of the risk management activities and positions. Our risk team reports directly to our Chief Financial Officer and their compensation is unrelated to trading activity. Commodity positions are typically reviewed and updated daily based on information from our customer databases and pricing information sources. The risk policy sets volumetric limits on intra-day and end of day long and short positions in natural gas and electricity. With respect to specific hedges, we have established and approved a formal delegation of authority specifying each trader's authorized volumetric limits based on instrument type, lead time (time to trade flow), fixed price volume, index price volume and tenor (trade flow) for individual transactions. The risk team reports to the risk committee any hedging transactions that exceed these delegated transaction limits. A discussion of the various risks we face in our risk management activities is as follows:

Commodity Price and Volumetric Risk

Because our contracts require that we deliver full natural gas or electricity requirements to our customers and because our customers’ usage can be impacted by factors such as weather, we may periodically purchase more or less commodity than our aggregate customer volumetric needs. In buying or selling excess volumes, we may be exposed to commodity price volatility. In order to address the potential volumetric variability of our monthly deliveries for fixed-price customers, we implement various hedging strategies to attempt to mitigate our exposure.

 

Our commodity risk management strategy is designed to hedge substantially all of our forecasted volumes on our fixed-price customer contracts, as well as a portion of the near-term volumes on our variable-price customer contracts. We use both physical and financial products to hedge our fixed-price exposure. The efficacy of our risk management program may be adversely impacted by unanticipated events and costs that we are not able to effectively hedge, including abnormal customer attrition and consumption, certain variable costs associated with electricity grid reliability, pricing differences in the local markets for local delivery of commodities, unanticipated events that impact supply and demand, such as extreme weather, and abrupt changes in the markets for, or availability or cost of, financial instruments that help to hedge commodity price.

Variability in customer demand is primarily impacted by weather. We use utility-provided historical and/or forward projected customer volumes as a basis for our forecasted volumes and mitigate the risk of seasonal volume fluctuation for some customers by purchasing excess fixed-price hedges within our volumetric tolerances. Should seasonal demand exceed our weather-normalized projections, we may experience a negative impact on our financial results.

From time to time, we also take further measures to reduce price risk and optimize our returns by: (i) maximizing the use of natural gas storage in our daily balancing market areas in order to give us the flexibility to offset volumetric variability arising from changes in winter demand; (ii) entering into daily swing contracts in our daily balancing markets over the winter months to enable us to increase or decrease daily volumes if demand increases or decreases; and (iii) purchasing out-of-the-money call options for contract periods with the highest seasonal volumetric risk to protect against steeply rising prices if our customer demands exceed our forecast. Being geographically diversified in our delivery areas also permits us, from time to time, to employ assets not being used

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in one area to other areas, thereby mitigating potential increased costs for natural gas that we otherwise may have had to acquire at higher prices to meet increased demand.

We utilize New York Mercantile Exchange (“NYMEX”) settled financial instruments to offset price risk associated with volume commitments under fixed-price contracts. The valuation for these financial instruments is calculated daily based on the NYMEX Exchange published closing price, and they are settled using the NYMEX Exchange’s published settlement price at their maturity.

Basis Risk

We are exposed to basis risk in our operations when the commodities we hedge are sold at different delivery points from the exposure we are seeking to hedge. For example, if we hedge our natural gas commodity price with Chicago basis but physical supply must be delivered to the individual delivery points of specific utility systems around the Chicago metropolitan area, we are exposed to the risk that prices may differ between the Chicago delivery point and the individual utility system delivery points. These differences can be significant from time to time, particularly during extreme, unforecasted cold weather conditions. Similarly, in certain of our electricity markets, customers pay the load zone price for electricity, so if we purchase supply to be delivered at a hub, we may have basis risk between the hub and the load zone electricity prices due to local congestion that is not reflected in the hub price. We attempt to hedge basis risk where possible, but hedging instruments are occasionally not economically feasible or available in the smaller quantities that we require.

Customer Credit Risk

Our credit risk management policies are designed to limit customer credit exposure. Credit risk is managed through participation in purchase of receivables ("POR") programs in utility service territories where such programs are available. In these markets, we monitor the credit ratings of the local regulated utilities and the parent companies of the utilities that purchase our customer accounts receivable. We also periodically review payment history and financial information for the local regulated utilities to ensure that we identify and respond to any deteriorating trends. In non-POR markets, we assess the creditworthiness of new applicants, monitor customer payment activities and administer an active collection program. Using risk models, past credit experience and different levels of exposure in each of the markets, we monitor our receivable aging, bad debt forecasts and actual bad debt expenses and continually adjust as necessary.

In territories where POR programs have been established, the local regulated utility purchases our receivables, and then becomes responsible for billing and collecting payment from the customer. In return for their assumption of risk, we receive slightly discounted proceeds on the receivables sold. POR programs result in substantially all of our credit risk being linked to the applicable utility and not to our end-use customers in these territories. For the year ended December 31, 2019, approximately 67% of our retail revenues were derived from territories in which substantially all of our credit risk was directly linked to local regulated utility companies, all of which had investment grade ratings. During the same period, we paid these local regulated utilities a weighted average discount of approximately 0.8% of total revenues for customer credit risk. In certain of the POR markets in which we operate, the utilities limit their collections exposure by retaining the ability to transfer a delinquent account back to us for collection when collections are past due for a specified period. If our subsequent collection efforts are unsuccessful, we return the account to the local regulated utility for termination of service. Under these service programs, we are exposed to credit risk related to payment for services rendered during the time between when the customer is transferred to us by the local regulated utility and the time we return the customer to the utility for termination of service, which is generally one to two billing periods. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract.

In non-POR markets (and in select POR markets where we may choose to direct bill our customers), we manage commercial customer credit risk through a formal credit review and manage residential customer credit risk through a variety of procedures, which may include credit score screening, deposits and disconnection for non-payment. We

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also maintain an allowance for doubtful accounts, which represents our estimate of potential credit losses associated with accounts receivable from customers within these markets.

We assess the adequacy of the allowance for doubtful accounts through review of an aging of customer accounts receivable and general economic conditions in the markets that we serve. Our bad debt expense for the year ended December 31, 2019 was $13.5 million, or 1.7% of retail revenues. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Drivers of Our Business—Customer Credit Risk” for a more detailed discussion of our bad debt expense for the year ended December 31, 2019.

We do not have high concentrations of sales volumes to individual customers. For the year ended December 31, 2019, our largest customer accounted for 1% of total retail energy sales volume.

Counterparty Credit Risk in Wholesale Markets

We do not independently produce natural gas and electricity and depend upon third parties for our supply, which exposes us to wholesale counterparty credit risk in our retail and asset optimization activities. If the counterparties to our supply contracts are unable to perform their obligations, we may suffer losses, including those that occur as a result of being unable to secure replacement supplies of natural gas or electricity on a timely or cost-effective basis or at all. At December 31, 2019, approximately $0.1 million of our total exposure of $3.1 million was either with a non-investment grade counterparty or otherwise not secured with collateral or a guarantee.

Operational Risk

As with all companies, we are at risk from cyber-attacks (breaches, unauthorized access, misuse, computer viruses, or other malicious code or other events) that could materially adversely affect our business, or otherwise cause interruptions or malfunctions in our operations. We mitigate these risks through multiple layers of security controls including policy, hardware, and software security solutions. We also have engaged third parties to assist with both external and internal vulnerability scans and continually enhance awareness through employee education and accountability. As of December 31, 2019, we have not experienced any material loss related to cyber-attacks or other information security breaches.

Relationship with our Founder and Majority Shareholder

We have historically leveraged our relationship with affiliates of our founder, chairman and majority shareholder, W. Keith Maxwell III (our "Founder"), to execute our strategy, including sourcing acquisitions, financing, and operations support. Our Founder owns National Gas & Electric, LLC (“NG&E”), which was formed for the purpose of purchasing retail energy companies and retail customer books that may ultimately be resold to the Company. This relationship has afforded us access to opportunities that may not have otherwise been available to us due to our size and availability of capital.

We may engage in additional transactions with NG&E in the future and expect that any such transactions would be funded by a combination of cash, subordinated debt, or the issuance of Class A or Class B common stock. Actual consideration paid for the assets would depend, among other things, on our capital structure and liquidity at the time of any transaction. Although we believe our Founder would be incentivized to offer us additional acquisition opportunities, he and his affiliates are under no obligation to do so, and we are under no obligation to buy assets from them. Any acquisition activity involving NG&E or any other affiliate of our Founder will be subject to negotiation and approval by a special committee of our Board of Directors consisting solely of independent directors. Please see “Risk Factors” related to acquisitions and transactions with our affiliates.

Competition

The markets in which we operate are highly competitive. Our primary competition comes from the incumbent utility and other independent retail energy companies. In the electricity sector, these competitors include larger,

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well-capitalized energy retailers such as Calpine Energy Solutions, LLC, Constellation Energy Group, Inc., Direct Energy, Inc., NRG Energy, Inc., and Vistra Energy Corp. We also compete with small local retail energy providers in the electricity sector that are focused exclusively on certain markets. Each market has a different group of local retail energy providers. In the natural gas sector, our national competitors are primarily Direct Energy and Constellation Energy. Our national competitors generally have diversified energy platforms with multiple marketing approaches and broad geographic coverage similar to us. Competition in each market is based primarily on product offering, price and customer service. The number of competitors in our markets varies. In well-established markets in the Northeast and Texas we have hundreds of competitors, while in other markets the competition is limited to several participants. Markets that offer POR programs are generally more competitive than those markets in which retail energy providers bear customer credit risk.

Our ability to compete depends on our ability to convince customers to switch to our products and services, renew services with customers upon expiration of their contract terms, and our ability to offer products at attractive prices. Many local regulated utilities and their affiliates may possess the advantages of name recognition, longer operating histories, long-standing relationships with their customers and access to financial and other resources, which could pose a competitive challenge to us. As a result of our competitors' advantages, many customers of these local regulated utilities may decide to stay with their longtime energy provider if they have been satisfied with their service in the past. In addition, competitors may choose to offer more attractive short-term pricing to increase their market share.

Seasonality of Our Business

Our overall operating results fluctuate substantially on a seasonal basis depending on: (i) the geographic mix of our customer base; (ii) the relative concentration of our commodity mix; (iii) weather conditions, which directly influence the demand for natural gas and electricity and affect the prices of energy commodities; and (iv) variability in market prices for natural gas and electricity. These factors can have material short-term impacts on monthly and quarterly operating results, which may be misleading when considered outside of the context of our annual operating cycle.

Our accounts payable and accounts receivable are impacted by seasonality due to the timing differences between when we pay our suppliers for accounts payable versus when we collect from our customers on accounts receivable. We typically pay our suppliers for purchases of natural gas on a monthly basis and electricity on a weekly basis. However, it takes approximately two months from the time we deliver the electricity or natural gas to our customers before we collect from our customers on accounts receivable attributable to those supplies. This timing difference affects our cash flows, especially during peak cycles in the winter and summer months.

Natural gas accounted for approximately 15% of our retail revenues for the year ended December 31, 2019, which exposes us to a high degree of seasonality in our cash flows and income earned throughout the year as a result of the high concentration of heating load in the winter months. We utilize a considerable amount of cash from operations and borrowing capacity to fund working capital, which includes inventory purchases from April through October each year. We sell our natural gas inventory during the months of November through March of each year. We expect that the significant seasonality impacts to our cash flows and income will continue in future periods.

 

Regulatory Environment

We operate in the highly regulated natural gas and electricity retail sales industry in all of our respective jurisdictions, and must comply with the legislation and regulations in these jurisdictions in order to maintain our licenses to operate. We must also comply with the applicable regulations in order to obtain the necessary licenses in jurisdictions in which we plan to compete. Licensing requirements vary by state, but generally involve regular, standardized reporting in order to maintain a license in good standing with the state commission responsible for regulating retail electricity and gas suppliers. We believe there is potential for changes to state legislation and regulatory measures addressing licensing requirements that may impact our business model in the applicable jurisdictions. In addition, as further discussed below, our marketing activities and customer enrollment procedures

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are subject to rules and regulations at the state and federal levels, and failure to comply with requirements imposed by federal and state regulatory authorities could impact our licensing in a particular market. See "Risk Factors—We face risks due to increasing regulation of the retail energy industry at the state level."

New York

A Low-Income Order was promulgated by the New York State Public Service Commission ("NYPSC") in December of 2016 (the "Low-Income Order"), and the New York State Supreme Court, Appellate Division, Third Department ruled in September 2017 that energy service companies ("ESCOs") must proceed with returning existing low-income customers to utility service and stop enrolling new low-income customers. The ESCOs have effectively exhausted their legal remedies to appeal this matter and must now comply with the Low-Income Order. ESCOs may continue serving low income customers if those customers are enrolled in fixed arrangements with guaranteed savings or with value add inclusions (that were entered into prior to the effective date of the Low-Income Order) or if the ESCO receives a waiver from the NYPSC to provide low-income customers with guaranteed savings. The Company and its subsidiaries have been returning low-income customers to the applicable utilities as they have rolled off of their contracts. As of December 31, 2019, remaining low-income customers represent approximately 1.3% of our total RCEs in New York and 0.2% of our RCEs overall.

In December 2019, the NYPSC issued its retail energy market reset order (the “December 2019 Reset Order”), that ESCOs will be required to comply with commencing early May 2020. The December 2019 Reset Order states that ESCOs can only enroll new residential or small nonresidential customers (mass-market customers) or renew existing mass-market customer contracts for gas and/or electric service only if at least one of the following conditions is met: (1) enrollment includes a guaranteed savings over the utility price, as reconciled on an annual basis; (2) enrollment is for a fixed-rate commodity product that is priced at no more than 5% greater than the trailing 12-month average utility supply rate; (3) enrollment is for a renewably sourced electric commodity product that (a) has a renewable mix that is at least 50% greater than the ESCO’s current Renewable Energy Standard (RES) obligation, (b) the ESCO complies with the RES locational and delivery requirements when procuring RECs or entering into bilateral contracts for renewable commodity supply, and (c) there is transparency of information and disclosures provided to the customer with respect to pricing and commodity sourcing.  In addition, by June 9, 2020, all New York ESCOs are directed to essentially re-apply for licenses to serve customers in New York.

We are evaluating the potential impact of the NYPSC's December 2019 Reset Order and subsequent proceedings on our New York operations while preparing to operate in compliance with any new requirements that may come as a result of any new order promulgated by the NYPSC. Given the uncertainty of the outcome of these matters and the final requirements that may be implemented, we are unable to predict at this time the magnitude of the long-term impact on our operations in New York.

Massachusetts

In October 2018, the Attorney General for the Commonwealth of Massachusetts filed suit against another ESCO and others alleging unfair or deceptive acts or practices in violation of a consumer protections act, breach of the covenant of good faith and fair dealing, and violation of the Massachusetts Telemarketing Solicitation Act. Contemporaneously with the filing of their complaint, the Commonwealth filed for injunctive relief seeking to attach purchase of receivables program revenues owed to the ESCO as possible damages. There can be no assurance that the Commonwealth will not pursue similar claims against other ESCOs.

Other States

Recently, certain state commissions have begun efforts to restrict the ability of retail suppliers to “pass through” costs to customers associated with certain changes in law or regulatory requirements. For example, on January 22, 2019, the New Jersey Board of Public Utilities (“NJ BPU”) sent a cease and desist letter to third party suppliers (“TPS”) in New Jersey instructing that a TPS may not charge a customer rate that is higher than the fixed rate applicable during the period for which that rate was fixed. The letter notified TPS that such increases were

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prohibited and instructed TPS to refund customers amounts charged in excess of the applicable fixed rate. Parties have challenged the NJ BPU’s letter and it is not clear at this time whether refunds will be required. Similarly, the Connecticut Public Utilities Regulatory Authority (“PURA”) recently opened a docket after receiving complaints regarding increases by suppliers to certain fixed-price supplier contracts due to change in law triggers. PURA will consider whether suppliers’ actions constitute unfair and deceptive trade practices or otherwise violates applicable laws. PURA is expected to issue a declaratory ruling following its review. Depending on the outcome of these efforts in New Jersey and Connecticut, the Company may be required to assume costs that it otherwise would pass on to customers under its change in law provisions and potentially provide refunds to certain customers.

Other Regulations

Our marketing efforts to consumers, including but not limited to telemarketing, door-to-door sales, direct mail and online marketing, are subject to consumer protection regulation including state deceptive trade practices acts, Federal Trade Commission ("FTC") marketing standards, and state utility commission rules governing customer solicitations and enrollments, among others. By way of example, telemarketing activity is subject to federal and state do-not-call regulation and certain enrollment standards promulgated by state regulators. Door-to-door sales are governed by the FTC’s “Cooling Off” Rule as well as state-specific regulation in many jurisdictions. In markets in which we conduct customer credit checks, these checks are subject to the requirements of the Fair Credit Reporting Act. Violations of the rules and regulations governing our marketing and sales activity could impact our license to operate in a particular market, result in suspension or otherwise limit our ability to conduct marketing activity in certain markets, and potentially lead to private actions against us. Moreover, there is potential for changes to legislation and regulatory measures applicable to our marketing measures that may impact our business models.

Recent interpretations of the Telephone Consumer Protection Act of 1991 (the “TCPA”) by the Federal Communications Commission (“FCC”) have introduced confusion regarding what constitutes an “autodialer” for purposes of determining compliance under the TCPA. Also, additional restrictions have been placed on wireless telephone numbers making compliance with the TCPA more costly. See “Risk Factors—Risks Related to Our Business and Our Industry—Liability under the TCPA has increased significantly in recent years, and we face risks if we fail to comply.”

As compliance with the federal TCPA regulations and state telemarketing regulations becomes increasingly costly and as door-to-door marketing becomes increasingly risky both from a regulatory compliance perspective, and from the risk of such activities drawing class action litigation claims, we and our peers who rely on these sales channels will find it more difficult than in the past to engage in direct marketing efforts. In response to these risks, we are experimenting with new technologies, such as a web-based application to process door-to-door sales enrollments with direct input by the consumer. This application can be accessed using tablets or any smart phone device, which enhances and expands the opportunities to market directly to customers.

Our participation in natural gas and electricity wholesale markets to procure supply for our retail customers and hedge pricing risk is subject to regulation by the Commodity Futures Trading Commission (the "CFTC"), including regulation pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act. In order to sell electricity, capacity and ancillary services in the wholesale electricity markets, we are required to have market-based rate authorization, also known as “MBR Authorization,” from the Federal Energy Regulatory Commission ("FERC"). We are required to make status update filings to FERC to disclose any affiliate relationships and quarterly filings to FERC regarding volumes of wholesale electricity sales in order to maintain our MBR Authorization. We are also required to seek prior approval by FERC to the extent any direct or indirect change in control occurs with respect to entities that hold MBR Authorization.

The transportation and sale for resale of natural gas in interstate commerce are regulated by agencies of the U.S. federal government, primarily FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service conditions, which affects our ability to procure natural gas supply for our retail customers and hedge pricing risk. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. FERC’s orders do not attempt to directly regulate natural gas retail

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sales. As a shipper of natural gas on interstate pipelines, we are subject to those interstate pipelines' tariff requirements and FERC regulations and policies applicable to shippers.

Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas marketers and local regulated utilities with which we compete.

In December 2007, FERC issued Order 704, a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas gatherers and marketers, are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting. As a wholesale buyer and seller of natural gas, we are subject to the reporting requirements of Order 704.

Employees

We employed 164 people as of December 31, 2019, none of which were subject to any collective bargaining agreements. We have not experienced any strikes or work stoppages and consider our relations with our employees to be satisfactory. We also utilize the services of independent contractors and vendors to perform various services.

Facilities

Our corporate headquarters is located in Houston, Texas, and we also maintain an office in Orangeburg, New York.

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Available Information

Our website is located at www.sparkenergy.com. We make available our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (the “SEC”), including our annual reports on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K, and all amendments to those reports, free of charge through our website, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Any materials filed with the SEC may be read and copied at the SEC’s website at www.sec.gov.

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Item 1A. Risk Factors

You should carefully consider the risks described below together with the other information contained in this Annual Report on Form 10-K. If any of the risks below were to occur, our business, financial condition, cash flows, results of operation and ability to pay dividends on our Class A common stock and Series A Preferred Stock could be adversely impacted, and the price of the Class A common stock and Series A Preferred Stock could decline and you could lose your investment.

Risks Related to Our Business and Our Industry

We are subject to commodity price risk.

Our financial results are largely dependent on the prices at which we can acquire the commodities we resell. The prevailing market prices for natural gas and electricity have historically, and may continue to fluctuate substantially over relatively short periods of time. Changes in market prices for natural gas and electricity may result from many factors that are outside of our control, including:

—	weather conditions;

—	seasonality;

—	demand for energy commodities and general economic conditions;

—	disruption of natural gas or electricity transmission or transportation infrastructure or other constraints or inefficiencies;

—	reduction or unavailability of generating capacity, including temporary outages, mothballing, or retirements;

—	the level of prices and availability of natural gas and competing energy sources, including the impact of changes in environmental regulations impacting suppliers;

—	the creditworthiness or bankruptcy or other financial distress of market participants;

—	changes in market liquidity;

—	natural disasters, wars, embargoes, acts of terrorism and other catastrophic events;

—	significant changes in the pricing methods in the wholesale markets in which we operate;

—	changes in regulatory policies concerning how markets are structured, how compensation is provided for service, and the kinds of different services that can or must be offered;

—	federal, state, foreign and other governmental regulation and legislation; and

—	demand side management, conservation, alternative or renewable energy sources.

We may not be able to pass along changes to the prices we pay to acquire commodities to our customers and such pricing fluctuations can attract consumer class actions as well as state and federal regulatory actions.

Our financial results may be adversely impacted by weather conditions.

Weather conditions directly influence the demand for and availability of natural gas and electricity and affect the prices of energy commodities. Generally, on most utility systems, demand for natural gas peaks in the winter and demand for electricity peaks in the summer. Typically, when winters are warmer or summers are cooler, demand for energy is lower than expected, resulting in less natural gas and electricity consumption than forecasted. When demand is below anticipated levels due to weather patterns, we may be forced to sell excess supply at prices below our acquisition cost, which could result in reduced margins or even losses.

Conversely, when winters are colder or summers are warmer, consumption may outpace the volumes of natural gas and electricity against which we have hedged, and we may be unable to meet increased demand with storage or swing supply. In these circumstances, we may experience reduced margins or even losses if we are required to purchase additional supply at higher prices. We may fail to accurately anticipate demand due to fluctuations in weather or to effectively manage our supply in response to a fluctuating commodity price environment.

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Our risk management policies and hedging procedures may not mitigate risk as planned, and we may fail to fully or effectively hedge our commodity supply and price risk.

To provide energy to our customers, we purchase commodities in the wholesale energy markets, which are often highly volatile. Our commodity risk management strategy is designed to hedge substantially all of our forecasted volumes on our fixed-price customer contracts, as well as a portion of the near-term volumes on our variable-price customer contracts. We use both physical and financial products to hedge our exposure. The efficacy of our risk management program may be adversely impacted by unanticipated events and costs that we are not able to effectively hedge, including abnormal customer attrition and consumption, certain variable costs associated with electricity grid reliability, pricing differences in the local markets for local delivery of commodities, unanticipated events that impact supply and demand, such as extreme weather, and abrupt changes in the markets for, or availability or cost of, financial instruments that help to hedge commodity price.

We are exposed to basis risk in our operations when the commodities we hedge are sold at different delivery points from the exposure we are seeking to hedge. For example, if we hedge our natural gas commodity price with Chicago basis but physical supply must be delivered to the individual delivery points of specific utility systems around the Chicago metropolitan area, we are exposed to basis risk between the Chicago basis and the individual utility system delivery points. These differences can be significant from time to time, particularly during extreme, unforecasted cold weather conditions. Similarly, in certain of our electricity markets, customers pay the load zone price for electricity, so if we purchase supply to be delivered at a hub, we may have basis risk between the hub and the load zone electricity prices due to local congestion that is not reflected in the hub price. We attempt to hedge basis risk where possible, but hedging instruments are sometimes not economically feasible or available in the smaller quantities that we require.

Additionally, assumptions that we use in establishing our hedges may reduce the effectiveness of our hedging instruments. Considerations that may affect our hedging policies include, but are not limited to, human error, assumptions about customer attrition, the relationship of prices at different trading or delivery points, assumptions about future weather, and our load forecasting models.

In addition, we incur costs monthly for ancillary charges such as reserves and capacity in the electricity sector by ISOs. For example, the ISOs will charge all retail electricity providers for monthly reserves that the ISO determines are necessary to protect the integrity of the grid. We attempt to estimate such amounts, but they are difficult to estimate because they are charged in arrears by the ISOs and are subject to fluctuations based on weather and other market conditions. We may be unable to fully pass the higher cost of ancillary reserves and reliability services through to our customers, and increases in the cost of these ancillary reserves and reliability services could negatively impact our results of operations.

Many of the natural gas utilities we serve allocate a share of transportation and storage capacity to us as a part of their competitive market operations. We are required to fill our allocated storage capacity with natural gas, which creates commodity supply and price risk. Sometimes we cannot hedge the volumes associated with these assets because they are too small compared to the much larger bulk transaction volumes required for trades in the wholesale market or it is not economically feasible to do so. In some regulatory programs or under some contracts, this capacity may be subject to recall by the utilities, which could have the effect of us being required to access the spot market to cover such a recall.

ESCOs face risks due to increased and rapidly changing regulations and increasing monetary fines by the state regulatory agencies.

The retail energy industry is highly regulated. Regulations may be changed or reinterpreted and new laws and regulations applicable to our business could be implemented in the future. To the extent that the competitive restructuring of retail electricity and natural gas markets is reversed, altered or discontinued, such changes could have a detrimental impact on our business and overall financial condition.

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Some states are beginning to increase their regulation of their retail electricity and natural gas markets in an effort to increase consumer disclosures and ensure marketing practices are not misleading to consumers. In addition, the fines against ESCOs that regulators are seeking has increased dramatically in recent years. For example, in 2015 the Connecticut Legislature passed legislation providing that licensed electric suppliers in Connecticut could no longer offer variable rate products as Connecticut regulators believed that a variable rate product was inappropriate for residential consumers.

In addition, in December 2019, the NYPSC issued its retail energy market reset order (the “December 2019 Reset Order”), that ESCOs will be required to comply with commencing early May 2020. The December 2019 Reset Order states that ESCOs can only enroll new residential or small nonresidential customers (mass-market customers) or renew existing mass-market customer contracts for gas and/or electric service only if at least one of the following conditions is met: (1) enrollment includes a guaranteed savings over the utility price, as reconciled on an annual basis; (2) enrollment is for a fixed-rate commodity product that is priced at no more than 5% greater than the trailing 12-month average utility supply rate; (3) enrollment is for a renewably sourced electric commodity product that (a) has a renewable mix that is at least 50% greater than the ESCO’s current Renewable Energy Standard (RES) obligation, (b) the ESCO complies with the RES locational and delivery requirements when procuring Renewable Energy Credits (RECs) or entering into bilateral contracts for renewable commodity supply, and (c) there is transparency of information and disclosures provided to the customer with respect to pricing and commodity sourcing.  In addition, by June 9, 2020, all New York ESCOs are directed to essentially re-apply for licenses to serve customers in New York.

We are evaluating the potential impact of the NYPSC's December 2019 Reset Order and subsequent proceedings on our New York operations while preparing to operate in compliance with any new requirements that may come as a result of any new order promulgated by the NYPSC. Given the uncertainty of the outcome of these matters and the final requirements that may be implemented, we are unable to predict at this time the magnitude of the long-term impact on our operations in New York.

Prior to the December 2019 Reset Order, the NYPSC implemented a low-income order that required ESCOs to return existing low-income customers to utility service and stop enrolling new low-income customers unless customers are enrolled in fixed arrangements with guaranteed savings or with value add inclusions (that were entered into prior to the effective date of the low-income order) or if the ESCO receives a waiver from the NYPSC to provide low-income customers with guaranteed savings. As a result of the low-income order, we have been dropping low-income customers back to the applicable utilities as they have rolled off of their contracts. As of December 31, 2019, remaining low-income customers represent approximately 1.3% of our total RCEs in New York and 0.2% of our RCEs overall. There can be no assurance that the NYPSC or state regulatory agencies to which we are subject will not continue trying to implement restrictive anti-competitive regulations on us.

On October 15, 2018, the Attorney General for the Commonwealth of Massachusetts filed suit against another ESCO and others alleging unfair or deceptive acts or practices in violation of a consumer protections act, breach of the covenant of good faith and fair dealing, and violation of the Massachusetts Telemarketing Solicitation Act. Contemporaneously with the filing of their complaint, the Commonwealth filed for injunctive relief seeking to attach purchase of receivables program revenues owed to the ESCO as possible damages. There can be no assurance that the Commonwealth will not pursue similar claims against other ESCOs.

Recently, certain state commissions have begun efforts to restrict the ability of retail suppliers to “pass through” costs to customers associated with certain changes in law or regulatory requirements. For example, on January 22, 2019, the New Jersey Board of Public Utilities ("NJ BPU") sent a cease and desist letter to third party suppliers ("TPS") in New Jersey instructing that a TPS may not charge a customer rate that is higher than the fixed rate applicable during the period for which that rate was fixed. The letter notified TPS that such increases were prohibited and instructed TPS to refund customers amounts charged in excess of the applicable fixed rate. Parties have challenged the NJ BPU’s letter and it is not clear at this time whether refunds will be required. Similarly, the Connecticut Public Utilities Regulatory Authority ("PURA") recently opened a docket after receiving complaints regarding increases by suppliers to certain fixed-price supplier contracts due to change in law triggers. PURA will consider whether suppliers’ actions constitute unfair and deceptive trade practices or otherwise violate applicable laws. PURA is expected to issue a declaratory ruling following its review. Depending on the outcome of these efforts in New Jersey and Connecticut,

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the Company may be required to assume costs that it otherwise would pass on to customers under its change in law provisions and potentially provide refunds to certain customers.

The retail energy business is subject to a high level of federal, state and local regulations, which are subject to change.

Our costs of doing business may fluctuate based on changing state, federal and local rules and regulations. For example, many electricity markets have rate caps, and changes to these rate caps by regulators can impact future price exposure. Similarly, regulatory changes can result in new fees or charges that may not have been anticipated when existing retail contracts were drafted, which can create financial exposure. Our ability to manage cost increases that result from regulatory changes will depend, in part, on how the “change in law provisions” of our contracts are interpreted and enforced, among other factors.

Liability under the TCPA has increased significantly in recent years, and we face risks if we fail to comply.

Our outbound telemarketing efforts and use of mobile messaging to communicate with our customers subjects us to regulation under the TCPA. Over the last several years, companies have been subject to significant liabilities as a result of violations of the TCPA, including penalties, fines and damages under class action lawsuits. In addition, the increased use by us and other consumer retailers of mobile messaging to communicate with our customers has created new issues of application of the TCPA to these communications. In 2015, the Federal Communications Commission issued several rulings that made compliance with the TCPA more difficult and costly. Our failure to effectively monitor and comply with our activities that are subject to the TCPA could result in significant penalties and the adverse effects of having to defend and ultimately suffer liability in a class action lawsuit related to such non-compliance.

We are also subject to liability under the TCPA for actions of our third party vendors who are engaging in outbound telemarketing efforts on our behalf. The issue of vicarious liability for the actions of third parties in violation of the TCPA remains unclear and has been the subject of conflicting precedent in the federal appellate courts. There can be no assurance that we may be subject to significant damages as a result of a class action lawsuit for actions of our vendors that we may not be able to control.

We are, and in the future may become, involved in legal and regulatory proceedings and, as a result, may incur substantial costs.

We are subject to lawsuits, claims and regulatory proceeds arising in the ordinary course of our business from time to time, including several purported class action lawsuits involving sales practices, telemarketing and TCPA claims, as well as contract disclosure claims and breach of contract claims. These are in various stages and are subject to substantial uncertainties concerning the outcome.

A negative outcome for any of these matters could result in significant damages. Litigation may also negatively impact us by requiring us to pay substantial settlements, increasing our legal costs, diverting management attention from other business issues or harming our reputation with customers.

For additional information regarding the nature and status of certain proceedings, see Note 14 "Commitments and Contingencies" to the audited consolidated financial statements.

Our business is dependent on retaining licenses in the markets in which we operate.

Our business model is dependent on continuing to be licensed in existing markets. We may have a license revoked or not be granted a renewal of a license, or our license could be adversely conditioned or modified (e.g., by increased bond posting obligations). For example, recently, an ESCO was banned by the Public Utilities Commission of Ohio from operating in Ohio for five years in response to allegations that it has misleading and deceptive marketing practices and charged customers four times the rate as compared to other electricity and gas suppliers.

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We may be subject to risks in connection with acquisitions, which could cause us to fail to realize many of the anticipated benefits of such acquisitions.

We have grown our business in part through strategic acquisition opportunities from third parties and from affiliates of our majority shareholder and may continue to do so in the future. Achieving the anticipated benefits of these transactions depends in part upon our ability to identify accretive acquisition targets, accurately assess the benefits and risks of the acquisition prior to undertaking it, and the ability to integrate the acquired businesses in an efficient and effective manner. When we identify an acquisition candidate, there is a risk that we may be unable to negotiate terms that are beneficial to us. Additionally, even if we identify an accretive acquisition target, the successful acquisition of that business requires estimating anticipated cash flow and accretive value, evaluating potential regulatory challenges, retaining customers and assuming liabilities. The accuracy of these estimates is inherently uncertain and our assumptions may turn out to be incorrect.

Furthermore, when we make an acquisition, we may not be able to accomplish the integration process smoothly or successfully. The difficulties of integrating acquisitions can include, among other things:

–	coordinating geographically separate organizations and addressing possible differences in corporate cultures and management philosophies;

–	dedicating significant management resources to the integration of the acquisition, which may temporarily distract management's attention from the day-to-day business of the combined company;

–	increased liquidity needs to support working capital for the purchase of natural gas and electricity supply to meet our customers’ needs, for the credit requirements of forward physical supply and for generally higher operating expenses;

–	operating in states and markets where we have not previously conducted business;

–	managing different and competing brands and retail strategies in the same markets;

–	coordinating customer information and billing systems and determining how to optimize those systems on a consolidated level;

–	ensuring our hedging strategy adequately covers a customer base that is managed through multiple systems;

–	successfully recognizing expected cost savings and other synergies in overlapping functions; and

–	incurring the responsibility and cost to defend and settle regulatory and litigation matters stemming from the acquired company’s pre-acquisition sales and marketing activities, which may not be covered by indemnification.

In many of our acquisition agreements, we are entitled to indemnification from the counterparty for various matters, including breaches of representations, warranties and covenants, tax matters, and litigation proceedings. We generally obtain security to provide assurances that the counterparty could perform its indemnification obligations, which may be in the form of escrow accounts, payment withholding or other methods. However, to the extent that we do not obtain security, or the security turns out to be inadequate, there is a risk that the counterparty may fail to perform on its indemnification obligations, which could result in the losses being incurred by us.

Our ability to grow at levels experienced historically may be constrained if the market for acquisition candidates is limited and we are unable to make acquisitions of portfolios of customers and retail energy companies on commercially reasonable terms.

Pursuant to our cash dividend policy, we distribute a significant portion of our cash through regular quarterly dividends, and our ability to grow and make acquisitions with cash on hand could be limited.

Pursuant to our cash dividend policy, we have historically distributed and intend in the future to distribute, a significant portion of our cash through regular quarterly dividends to holders of our Class A common stock and dividends on our Series A Preferred Stock. As such, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations, and we may have to rely upon external financing sources, including the issuance of debt, equity securities, convertible subordinated notes and borrowings under our Senior

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Credit Facility and Subordinated Facility. These sources may not be available, and our ability to grow and maintain our business may be limited.

We may not be able to manage our growth successfully.

The growth of our operations will depend upon our ability to expand our customer base in our existing markets and to enter new markets in a timely manner at reasonable costs, organically or through acquisitions. In order for us to recover expenses incurred in entering new markets and obtaining new customers, we must attract and retain customers on economic terms and for extended periods. We may experience difficulty managing our growth and implementing new product offerings, integrating new customers and employees, and complying with applicable market rules and the infrastructure for product delivery.

Expanding our operations also may require continued development of our operating and financial controls and may place additional stress on our management and operational resources. We may be unable to manage our growth and development successfully.

Our financial results fluctuate on a seasonal, quarterly and annual basis.

Our overall operating results fluctuate substantially on a seasonal, quarterly and annual basis depending on: (1) the geographic mix of our customer base; (2) the relative concentration of our commodity mix; (3) weather conditions, which directly influence the demand for natural gas and electricity and affect the prices of energy commodities; and (4) variability in market prices for natural gas and electricity. These factors can have material short-term impacts on monthly and quarterly operating results, which may be misleading when considered outside of the context of our annual operating cycle. In addition, our accounts payable and accounts receivable are impacted by seasonality due to the timing differences between when we pay our suppliers for accounts payable versus when we collect from our customers on accounts receivable. We typically pay our suppliers for purchases of natural gas on a monthly basis and electricity on a weekly basis. However, it takes approximately two months from the time we deliver the electricity or natural gas to our customers before we collect from our customers on accounts receivable attributable to those supplies. This timing difference could affect our cash flows, especially during peak cycles in the winter and summer months. Furthermore, as a result of the seasonality of our business, we may reserve a portion of our excess cash available for distribution in the first and fourth quarters in order to fund our second and third quarter distributions.

Additionally, we enter into a variety of financial derivative and physical contracts to manage commodity price risk, and we use mark-to-market accounting to account for this hedging activity. Under the mark-to-market accounting method, changes in the fair value of our hedging instruments that are not qualifying or not designated as hedges under accounting rules are recognized immediately in earnings. As a result of this accounting treatment, changes in the forward prices of natural gas and electricity cause volatility in our quarterly and annual earnings, which we are unable to fully anticipate.

We could also incur volatility from quarter to quarter associated with gains and losses on settled hedges relating to natural gas held in inventory if we choose to hedge the summer-winter spread on our retail allocated storage capacity. We typically purchase natural gas inventory and store it from April to October for withdrawal from November through March. Since a portion of the inventory is used to satisfy delivery obligations to our fixed-price customers over the winter months, we hedge the associated price risk using derivative contracts. Any gains or losses associated with settled derivative contracts are reflected in the statement of operations as a component of retail cost of sales and net asset optimization.

We may have difficulty retaining our existing customers or obtaining a sufficient number of new customers, due to competition and for other reasons.

The markets in which we compete are highly competitive, and we may face difficulty retaining our existing customers or obtaining new customers due to competition. We encounter significant competition from local regulated utilities or their retail affiliates and traditional and new retail energy providers. Many of these competitors

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or potential competitors are larger than us, have access to more significant capital resources, have more well-established brand names and have larger existing installed customer bases.

Additionally, existing customers may switch to other retail energy service providers during their contract terms in the event of a significant decrease in the retail price of natural gas or electricity in order to obtain more favorable prices. Although we generally have a right to collect a termination fee from each customer on a fixed-price contract who terminates their contract early, we may not be able to collect the termination fees in full or at all. Our variable-price contracts can typically be terminated by our customers at any time without penalty. We may be unable to obtain new customers or maintain our existing customers due to competition or otherwise.

Increased collateral requirements in connection with our supply activities may restrict our liquidity.

Our contractual agreements with certain local regulated utilities and our supplier counterparties require us to maintain restricted cash balances or letters of credit as collateral for credit risk or the performance risk associated with the future delivery of natural gas or electricity. These collateral requirements may increase as we grow our customer base. Collateral requirements will increase based on the volume or cost of the commodity we purchase in any given month and the amount of capacity or service contracted for with the local regulated utility. Significant changes in market prices also can result in fluctuations in the collateral that local regulated utilities or suppliers require.

The effectiveness of our operations and future growth depend in part on the amount of cash and letters of credit available to enter into or maintain these contracts. The cost of these arrangements may be affected by changes in credit markets, such as interest rate spreads in the cost of financing between different levels of credit ratings. These liquidity requirements may be greater than we anticipate or are able to meet.

We are subject to direct credit risk for certain customers who may fail to pay their bills as they become due.

We bear direct credit risk related to customers located in markets that have not implemented POR programs as well as indirect credit risk in those POR markets that pass collection efforts along to us after a specified non-payment period. For the year ended December 31, 2019, customers in non-POR markets represented approximately 33% of our retail revenues. We generally have the ability to terminate contracts with customers in the event of non-payment, but in most states in which we operate we cannot disconnect their natural gas or electricity service. In POR markets where the local regulated utility has the ability to return non-paying customers to us after specified periods, we may realize a loss for one to two billing periods until we can terminate these customers’ contracts. We may also realize a loss on fixed-price customers in this scenario due to the fact that we will have already fully hedged the customer’s expected commodity usage for the life of the contract and we also remain liable to our suppliers of natural gas and electricity for the cost of our supply commodities. Furthermore, in the Texas market, we are responsible for billing the distribution charges for the local regulated utility and are at risk for these charges, in addition to the cost of the commodity, in the event customers fail to pay their bills. Changing economic factors, such as rising unemployment rates and energy prices also result in a higher risk of customers being unable to pay their bills when due.

We depend on the accuracy of data in our information management systems, which subjects us to risks.

We depend on the accuracy and timeliness of our information management systems for billing, collections, consumption and other important data. We rely on many internal and external sources for this information, including:

—	our marketing, pricing and customer operations functions; and

—	various local regulated utilities and ISOs for volume or meter read information, certain billing rates and billing types (e.g., budget billing) and other fees and expenses.

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Inaccurate or untimely information, which may be outside of our direct control, could result in:

—	inaccurate and/or untimely bills sent to customers;

—	incorrect tax remittances;

—	reduced effectiveness and efficiency of our operations;

—	inability to adequately hedge our portfolio;

—	increased overhead costs;

—	inaccurate accounting and reporting of customer revenues, gross margin and accounts receivable activity;

—	inaccurate measurement of usage rates, throughput and imbalances;

—	customer complaints; and

—	increased regulatory scrutiny.

We are also subject to disruptions in our information management systems arising out of events beyond our control, such as natural disasters, pandemics, epidemics, failures in hardware or software, power fluctuations, telecommunications and other similar disruptions. In addition, our information management systems may be vulnerable to computer viruses, incursions by intruders or hackers and cyber terrorists and other similar disruptions. A cyber-attack on our information management systems could severely disrupt business operations, preventing us from billing and collecting revenues, and could result in significant expenses to investigate and repair security breaches or system damage, lead to litigation, fines, other remedial action, heightened regulatory scrutiny, diminished customer confidence and damage to our reputation. Although we maintain cyber-liability insurance that covers certain damage caused by cyber events, it may not be sufficient to cover us in all circumstances.

Our success depends on key members of our management, the loss of whom could disrupt our business operations.

We depend on the continued employment and performance of key management personnel. A number of our senior executives have substantial experience in consumer and energy markets that have undergone regulatory restructuring and have extensive risk management and hedging expertise. We believe their experience is important to our continued success. We do not maintain key life insurance policies for our executive officers. Our key executives may not continue in their present roles and may not be adequately replaced.

We rely on third party vendors for our customer billing and transactions platform that exposes us to third party performance risk.

We have outsourced our back office customer billing and transactions platforms to third party vendors, and we rely heavily on the continued performance of the vendors under our current outsourcing agreement. Our vendors may fail to operate in accordance with the terms of the outsourcing agreement or a bankruptcy or other event may prevent it from performing under our outsourcing agreement.

A large portion of our current customers are concentrated in a limited number of states, making us vulnerable to customer concentration risks.

As of December 31, 2019, approximately 59% of our RCEs were located in five states. Specifically, 16%, 12%, 12%, 10% and 9% of our customers on an RCE basis were located in NY, MA, PA, CT and TX, respectively. If we are unable to increase our market share across other competitive markets or enter into new competitive markets effectively, we may be subject to continued or greater customer concentration risk. The states that contain a large percentage of our customers could reverse regulatory restructuring or change the regulatory environment in a manner that causes us to be unable to operate economically in that state.

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Increases in state renewable portfolio standards or an increase in the cost of renewable energy credit and carbon offsets may adversely impact the price, availability and marketability of our products.

Pursuant to state renewable portfolio standards, we must purchase a specified amount of RECs based on the amount of electricity we sell in a state in a year. In addition, we have contracts with certain customers that require us to purchase RECs or carbon offsets. If a state increases its renewable portfolio standards, the demand for RECs within that state will increase and therefore the market price for RECs could increase. We attempt to forecast the price for the required RECs and carbon offsets at the end of each month and incorporate this forecast into our customer pricing models, but the price paid for RECs and carbon offsets may be higher than forecasted. We may be unable to fully pass the higher cost of RECs through to our customers, and increases in the price of RECs may decrease our results of operations and affect our ability to compete with other energy retailers that have not contracted with customers to purchase RECs or carbon offsets. Further, a price increase for RECs or carbon offsets may require us to decrease the renewable portion of our energy products, which may result in a loss of customers. A further reduction in benefits received by local regulated utilities from production tax credits in respect of renewable energy may adversely impact the availability to us, and marketability by us, of renewable energy under our brands.

Our access to marketing channels may be contingent upon the viability of our telemarketing and door-to-door agreements with our vendors.

Our vendors are essential to our telemarketing and door-to-door sales activities. Our ability to increase revenues in the future will depend significantly on our access to high quality vendors. If we are unable to attract new vendors and retain existing vendors to achieve our marketing targets, our growth may be materially reduced. There can be no assurance that competitive conditions will allow these vendors and their independent contractors to continue to successfully sign up new customers. Further, if our products are not attractive to, or do not generate sufficient revenue for our vendors, we may lose our existing relationships. In addition, the decline in landlines reduces the number of potential customers that may be reached by our telemarketing efforts and as a result our telemarketing sales channel may become less viable and we may be required to use more door-to-door marketing. Door-to-door marketing is continually under scrutiny by state regulators and legislators, which may lead to new rules and regulations that impact our ability to use these channels.

Our vendors may expose us to risks.

We are subject to reputational risks that may arise from the actions of our vendors and their independent contractors that are wholly or partially beyond our control, such as violations of our marketing policies and procedures as well as any failure to comply with applicable laws and regulations. If our vendors engage in marketing practices that are not in compliance with local laws and regulations, we may be in breach of applicable laws and regulations that may result in regulatory proceedings, disadvantageous conditioning of our energy retailer license, or the revocation of our energy retailer license. Unauthorized activities in connection with sales efforts by agents of our vendors, including calling consumers in violation of the TCPA and predatory door-to-door sales tactics and fraudulent misrepresentation could subject us to class action lawsuits against which we will be required to defend. Such defense efforts will be costly and time consuming. In addition, the independent contractors of our vendors may consider us to be their employer and seek compensation.

Risks Related to Our Capital Structure and Capital Stock

Our indebtedness could adversely affect our ability to raise additional capital to fund our operations or pay dividends. It could also expose us to the risk of increased interest rates and limit our ability to react to changes in the economy or our industry as well as impact our cash available for distribution.

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We have $123.0 million of indebtedness outstanding and $37.4 million in issued letters of credit under our Senior Credit Facility, and zero of indebtedness outstanding under our Subordinated Facility as of December 31, 2019. Debt we incur under our Senior Credit Facility, Subordinated Facility or otherwise could have negative consequences, including:

—	increasing our vulnerability to general economic and industry conditions;

—	requiring cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing or eliminating our ability to pay dividends to holders of our Class A common stock and Series A Preferred Stock, or to use our cash flow to fund our operations, capital expenditures and future business opportunities;

—	limiting our ability to fund future acquisitions or engage in other activities that we view as in our long-term best interest;

—	restricting our ability to make certain distributions with respect to our capital stock and the ability of our subsidiaries to make certain distributions to us, in light of restricted payment and other financial covenants, including requirements to maintain certain financial ratios, in our credit facilities and other financing agreements;

—	exposing us to the risk of increased interest rates because certain of our borrowings are at variable rates of interest; and

—	limiting our ability to obtain additional financing for working capital including collateral postings, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes.

If we are unable to satisfy financial covenants in our debt instruments, it could result in an event of default that, if not cured or waived, may entitle the lenders to demand repayment or enforce their security interests. Our Senior Credit Facility will mature in May 2021, and we cannot assure that we will be able to negotiate a new credit arrangement on commercially reasonable terms.

We cannot assure you that we will be able to continue paying our targeted quarterly dividend to the holders of our Class A common stock or dividends to the holders of our Series A Preferred Stock in the future.

The amount of our cash available for distribution principally depends upon the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:

—	changes in commodity prices, which may be driven by a variety of factors, including, but not limited to, weather conditions, seasonality and demand for energy commodities and general economic conditions;

—	the level and timing of customer acquisition costs we incur;

—	the level of our operating and general and administrative expenses;

—	seasonal variations in revenues generated by our business;

—	our debt service requirements and other liabilities;

—	fluctuations in our working capital needs;

—	our ability to borrow funds and access capital markets;

—	restrictions contained in our debt agreements (including our Senior Credit Facility);

—	management of customer credit risk;

—	abrupt changes in regulatory policies; and,

—	other business risks affecting our cash flows.

As a result of these and other factors, we cannot guarantee that we will have sufficient cash generated from operations to pay the dividends on our Series A Preferred Stock or to pay a specific level of cash dividends to holders of our Class A common stock.

The amount of cash available for distribution depends primarily on our cash flow, and is not solely a function of profitability, which is affected by non-cash items. We may incur other expenses or liabilities during a period that could significantly reduce or eliminate our cash available for distribution and, in turn, impair our ability to pay

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dividends to holders of our Class A common stock and Series A Preferred Stock during the period. Additionally, the dividends paid on Series A Preferred Stock reduce the amount of cash we have available to pay dividends on our Class A common stock.

Each new share of Class A common stock and Series A Preferred Stock issued increases the cash required to continue to pay cash dividends. Any Class A common stock or preferred stock (whether Series A Preferred Stock or a new series of preferred stock) that may in the future be issued to finance acquisitions, upon exercise of stock options or otherwise, would have a similar effect.

Finally, dividends to holders of our Class A common stock are paid at the discretion of our board of directors. Our board of directors may decrease the level of or entirely discontinue payment of dividends.

We could be prevented from paying cash dividends on the Class A common stock and Series A Preferred Stock.

Holders of shares of Class A common stock and Series A Preferred Stock do not have a right to dividends on such shares unless declared or set aside for payment by our board of directors. Under Delaware law, cash dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from the corporation’s net profits for the then-current or the preceding fiscal year. Unless we operate profitably, our ability to pay cash dividends on the Class A common stock and Series A Preferred Stock would require the availability of adequate “surplus,” which is defined as the excess, if any, of net assets (total assets less total liabilities) over capital. Our business may not generate sufficient cash flow from operations to enable us to pay dividends on the Series A Preferred Stock when payable, and quarterly dividends on the Class A common stock. Further, even if adequate surplus is available to pay cash dividends on the Class A common stock and Series A Preferred Stock, we may not have sufficient cash to pay dividends on the Class A common stock or Series A Preferred Stock.

Furthermore, no dividends on Class A common stock or Series A Preferred Stock shall be authorized by our board of directors or paid, declared or set aside for payment by us at any time when the authorization, payment, declaration or setting aside for payment would be unlawful under Delaware law or any other applicable law, or when the terms and provisions of any documents limiting the payment of dividends prohibit the authorization, payment, declaration or setting aside for payment thereof or would constitute a breach or a default under such document.

We are a holding company. Our sole material asset is our equity interest in Spark HoldCo, LLC ("Spark HoldCo") and we are accordingly dependent upon distributions from Spark HoldCo to pay dividends on the Class A common stock and Series A Preferred Stock.

We are a holding company and have no material assets other than our equity interest in Spark HoldCo, and have no independent means of generating revenue. Spark HoldCo or its subsidiaries may be restricted from making distributions to us under applicable law or regulation or under the terms of their financing arrangements, or may otherwise be unable to provide such funds.

The Class A common stock and Series A Preferred Stock are subordinated to our existing and future debt obligations.

The Class A common stock and Series A Preferred Stock are subordinated to all of our existing and future indebtedness (including indebtedness outstanding under the Senior Credit Facility). Therefore, if we become bankrupt, liquidate our assets, reorganize or enter into certain other transactions, assets will be available to pay our obligations with respect to the Series A Preferred Stock only after we have paid all of our existing and future indebtedness in full. The Class A common stock will only receive assets to the extent all existing and future indebtedness and obligations under the Series A Preferred Stock is paid in full. If any of these events were to occur, there may be insufficient assets remaining to make any payments to holders of the Series A Preferred Stock or Class A common stock.

Additionally, none of our subsidiaries have guaranteed or otherwise become obligated with respect to the Class A common stock or Series A Preferred Stock. As a result, the Class A common stock and Series A Preferred Stock

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effectively rank junior to all existing and future indebtedness and other liabilities of our subsidiaries, including our operating subsidiaries, and any capital stock of our subsidiaries not held by us. Accordingly, our right to receive assets from any of our subsidiaries upon our bankruptcy, liquidation or reorganization, and the right of holders of shares of Class A common stock and Series A Preferred Stock to participate in those assets, is also structurally subordinated to claims of that subsidiary’s creditors, including trade creditors. Even if we were a creditor of any of our subsidiaries, our rights as a creditor would be subordinate to any security interest in the assets of that subsidiary and any indebtedness of that subsidiary senior to that held by us.

Numerous factors may affect the trading price of the Class A common stock and Series A Preferred Stock.

The trading price of the Class A common stock and Series A Preferred Stock may depend on many factors, some of which are beyond our control, including:

—	prevailing interest rates;

—	the market for similar securities;

—	general economic and financial market conditions;

—	our issuance of debt or other preferred equity securities; and

—	our financial condition, results of operations and prospects.

One of the factors that will influence the price of the Class A common stock and Series A Preferred Stock will be the distribution yield of the securities (as a percentage of the then market price of the securities) relative to market interest rates. Increases in market interest rates, which have been at low levels relative to historical rates, may lead prospective purchasers of shares of Class A common stock or Series A Preferred Stock to expect a higher distribution yield, and cause them to sell their Class A common stock or Series A Preferred Stock. Accordingly, higher market interest rates could cause the market price of the Class A common stock and Series A Preferred Stock to decrease.

In addition, over the last several years, prices of equity securities in the U.S. trading markets have been experiencing extreme price fluctuations. As a result of these and other factors, investors holding our Class A common stock and Series A Preferred Stock may experience a decrease in the value of their securities, which could be substantial and rapid, and could be unrelated to our financial condition, performance or prospects.

There may not be an active trading market for the Class A common stock or Series A Preferred Stock, which may in turn reduce the market value and your ability to transfer or sell your shares of Class A common stock or Series A Preferred Stock.

There are no assurances that there will be an active trading market for our Class A common stock or Series A Preferred Stock. The liquidity of any market for the Class A common stock and Series A Preferred Stock depends upon the number of stockholders, our results of operations and financial condition, the market for similar securities, the interest of securities dealers in making a market in the Class A common stock and Series A Preferred Stock, and other factors. To the extent that an active trading market is not maintained, the liquidity and trading prices for the Class A common stock and Series A Preferred Stock may be harmed.

Furthermore, because the Series A Preferred Stock does not have any stated maturity and is not subject to any sinking fund or mandatory redemption, stockholders seeking liquidity will be limited to selling their respective shares of Series A Preferred Stock in the secondary market. Active trading markets for the Series A Preferred Stock may not exist at such times, in which case the trading price of your shares of our Series A Preferred Stock could be reduced and your ability to transfer such shares could be limited.

Our Founder holds a substantial majority of the voting power of our common stock.

Holders of Class A and Class B common stock vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or our certificate of

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incorporation and bylaws. Our Founder controls 66.3% of the combined voting power of the Class A and Class B common stock as of December 31, 2019 through his direct and indirect ownership in us.

Affiliated owners are entitled to act separately with respect to their investment in us, and they have the ability to elect all of the members of our board of directors, and thereby to control our management and affairs. In addition, affiliates are able to determine the outcome of all matters requiring Class A common stock and Class B common stock shareholder approval, including mergers and other material transactions, and is able to cause or prevent a change in the composition of our board of directors or a change in control of our company that could deprive our stockholders of an opportunity to receive a premium for their Class A common stock as part of a sale of our company. The existence of a significant shareholder, such as our Founder, may also have the effect of deterring hostile takeovers, delaying or preventing changes in control or changes in management, or limiting the ability of our other stockholders to approve transactions that they may deem to be in the best interests of our company.

So long as affiliates continue to control a significant amount of our common stock, they will continue to be able to strongly influence all matters requiring shareholder approval, regardless of whether other stockholders believe that a potential transaction is in their own best interests. In any of these matters, the interests of affiliates may differ or conflict with the interests of our other stockholders. Moreover, this concentration of stock ownership may also adversely affect the trading price of our Class A common stock or Series A Preferred Stock to the extent investors perceive a disadvantage in owning stock of a company with a controlling shareholder.

Holders of Series A Preferred Stock have extremely limited voting rights.

Voting rights of holders of shares of Series A Preferred Stock are extremely limited. Our Class A common stock and our Class B common stock are the only classes of our securities carrying full voting rights. Holders of the Series A Preferred Stock generally have no voting rights.

We have engaged in transactions with our affiliates in the past and expect to do so in the future. The terms of such transactions and the resolution of any conflicts that may arise may not always be in our or our stockholders’ best interests.

We have engaged in transactions and expect to continue to engage in transactions with affiliated companies. We have acquired companies and books of customers from our affiliates and may do so in the future. We will continue to enter into back-to-back transactions for purchases of commodities and derivatives on behalf of our affiliate. We will also continue to pay certain expenses on behalf of several of our affiliates for which we will seek reimbursement. We will also continue to share our corporate headquarters with certain affiliates. We cannot assure that our affiliates will reimburse us for the costs we have incurred on their behalf or perform their obligations under any of these contracts.

Our amended and restated certificate of incorporation and amended and restated bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our Class A common stock.

Our amended and restated certificate of incorporation authorizes our board of directors to issue preferred stock without shareholder approval. On September 20, 2019, we filed a registration statement under the Securities Act on Form S-3 allowing us to offer and sell, from time to time, shares of preferred stock. The registration statement was declared effective on October 18, 2019. The election by our board of directors to issue preferred stock with anti-takeover provisions could make it more difficult for a third party to acquire us.

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In addition, some provisions of our amended and restated certificate of incorporation and amended and restated bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. Among other things, our amended and restated certificate of incorporation and amended and restated bylaws:

—

provide for our board of directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three year terms. Our staggered board may tend to discourage a third party from making a tender offer or otherwise attempting to obtain control of us, because it generally makes it more difficult for shareholders to replace a majority of the directors;

—	provide that the authorized number of directors may be changed only by resolution of the board of directors;

—	provide that all vacancies in our board, including newly created directorships, may, except as otherwise required by law or, if applicable, the rights of holders of a series of preferred stock, be filled by the affirmative vote of a majority of directors then in office, even if less than a quorum;

—

provide our board of directors the ability to authorize undesignated preferred stock. This ability makes it possible for our board of directors to issue, without shareholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us. These and other provisions may have the effect of deferring hostile takeovers or delaying changes in control or management of our company;

—

provide that at any time after the first date upon which W. Keith Maxwell III no longer beneficially owns more than fifty percent of the outstanding Class A common stock and Class B common stock, any action required or permitted to be taken by the shareholders must be effected at a duly called annual or special meeting of shareholders and may not be effected by any consent in writing in lieu of a meeting of such shareholders, subject to the rights of the holders of any series of preferred stock with respect to such series (prior to such time, such actions may be taken without a meeting by written consent of holders of the outstanding stock having not less than the minimum number of votes that would be necessary to authorize or take such action at a meeting);

—

provide that at any time after the first date upon which W. Keith Maxwell III no longer beneficially owns more than fifty percent of the outstanding Class A common stock and Class B common stock, special meetings of our shareholders may only be called by the board of directors, the chief executive officer or the chairman of the board (prior to such time, special meetings may also be called by our Secretary at the request of holders of record of fifty percent of the outstanding Class A common stock and Class B common stock);

—	provide that our amended and restated certificate of incorporation and amended and restated bylaws may be amended by the affirmative vote of the holders of at least two-thirds of our outstanding stock entitled to vote thereon;

—	provide that our amended and restated bylaws can be amended by the board of directors; and

—

establish advance notice procedures with regard to shareholder proposals relating to the nomination of candidates for election as directors or new business to be brought before meetings of our shareholders. These procedures provide that notice of shareholder proposals must be timely given in writing to our corporate secretary prior to the meeting at which the action is to be taken. These requirements may preclude shareholders from bringing matters before the shareholders at an annual or special meeting.

In addition, in our amended and restated certificate of incorporation, we have elected not to be subject to the provisions of Section 203 of the Delaware General Corporation Law (the “DGCL”) regulating corporate takeovers until the date on which W. Keith Maxwell III no longer beneficially owns in the aggregate more than fifteen percent of the outstanding Class A common stock and Class B common stock. On and after such date, we will be subject to the provisions of Section 203 of the DGCL.

Our amended and restated certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our

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stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our amended and restated certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim against us or any director or officer or other employee of ours arising pursuant to any provision of the DGCL, our amended and restated certificate of incorporation or our bylaws, or (iv) any action asserting a claim against us or any director or officer or other employee of ours that is governed by the internal affairs doctrine, in each such case subject to such Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. This exclusive forum provision would not apply to suits brought to enforce any liability or duty created by the Securities Act or the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. To the extent that any such claims may be based upon federal law claims, Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Furthermore, Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts over all suits brought to enforce any duty or liability created by the Securities Act or the rules and regulations thereunder.

Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of our amended and restated certificate of incorporation described in the preceding sentence. This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our amended and restated certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition or results of operations.

Future sales of our Class A common stock and Series A Preferred Stock in the public market could reduce the price of the Class A common stock and Series A Preferred Stock, and may dilute your ownership in us.

On September 20, 2019, we filed a registration statement under the Securities Act on Form S-3 registering the primary offer and sale, from time to time, of Class A common stock, preferred stock, depositary shares and warrants. The registration statement also registers the Class A common stock held by our affiliates, Retailco and NuDevco (including Class A common stock that may be obtained upon conversion of Class B common stock). All of the shares of Class A common stock held by Retailco and NuDevco and registered on the registration statement may be immediately resold. The registration statement was declared effective on October 18, 2019.

We cannot predict the size of future issuances of our Class A common stock or securities convertible into Class A common stock or the effect, if any, that future issuances or sales of shares of our Class A common stock will have on the market price of our Class A common stock. Sales of substantial amounts of our Class A common stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our Class A common stock.

We may also in the future sell additional shares of preferred stock, including shares of Series A Preferred Stock, on terms that may differ from those we have previously issued. Such shares could rank on parity with or, subject to the voting rights referred to above (with respect to issuances of new series of preferred stock), senior to the Series A Preferred Stock as to distribution rights or rights upon liquidation, winding up or dissolution. The subsequent issuance of additional shares of Series A Preferred Stock, or the creation and subsequent issuance of additional classes of preferred stock on parity with the Series A Preferred Stock, could dilute the interests of the holders of Series A Preferred Stock, and could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Series A Preferred Stock. Any issuance of preferred stock that is senior to the Series A Preferred

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Stock would not only dilute the interests of the holders of Series A Preferred Stock, but also could affect our ability to pay distributions on, redeem or pay the liquidation preference on the Series A Preferred Stock.

Furthermore, subject to compliance with the Securities Act or exemptions therefrom, employees who have received Class A common stock as equity awards may also sell their shares into the public market.

We have issued preferred stock and may continue to do so, and the terms of such preferred stock could adversely affect the voting power or value of our Class A common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our Class A common stock with respect to dividends and distributions, as our board of directors may determine. Through December 31, 2019, we have issued an aggregate of 3,707,256 shares of Series A Preferred Stock.

The terms of the preferred stock we offer or sell could adversely impact the voting power or value of our Class A common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock, such as the Series A Preferred Stock, could affect the residual value of the Class A common stock.

Our amended and restated certificate of incorporation limits the fiduciary duties of one of our directors and certain of our affiliates and restricts the remedies available to our stockholders for actions taken by our Founder or certain of our affiliates that might otherwise constitute breaches of fiduciary duty.

Our amended and restated certificate of incorporation contains provisions that we renounce any interest in existing and future investments in other entities by, or the business opportunities of, NuDevco Partners, LLC, NuDevco Partners Holdings, LLC and W. Keith Maxwell III, or any of their officers, directors, agents, shareholders, members, affiliates and subsidiaries (other than a director or officer who is presented an opportunity solely in his capacity as a director or officer). Because of this provision, these persons and entities have no obligation to offer us those investments or opportunities that are offered to them in any capacity other than solely as an officer or director. If one of these persons or entities pursues a business opportunity instead of presenting the opportunity to us, we will not have any recourse against such person or entity for a breach of fiduciary duty.

The Series A Preferred Stock represent perpetual equity interests in us, and investors should not expect us to redeem the Series A Preferred Stock on the date the Series A Preferred Stock becomes redeemable by us or on any particular date afterwards.

The Series A Preferred Stock represents a perpetual equity interest in us, and the securities have no maturity or mandatory redemption date and are not redeemable at the option of investors under any circumstances. As a result, unlike our indebtedness, the Series A Preferred Stock will not give rise to a claim for payment of a principal amount at a particular date. As a result, holders of the Series A Preferred Stock may be required to bear the financial risks of an investment in the Series A Preferred Stock for an indefinite period of time. In addition, the Series A Preferred Stock will rank junior to all our current and future indebtedness (including indebtedness outstanding under the Senior Credit Facility) and other liabilities. The Series A Preferred Stock will also rank junior to any other preferred stock ranking senior to the Series A Preferred Stock we may issue in the future with respect to assets available to satisfy claims against us.

The Series A Preferred Stock is not rated.

We have not sought to obtain a rating for the Series A Preferred Stock, and the Series A Preferred Stock may never be rated. It is possible, however, that one or more rating agencies might independently determine to assign a rating to the Series A Preferred Stock or that we may elect to obtain a rating of the Series A Preferred Stock in the future. In addition, we may elect to issue other securities for which we may seek to obtain a rating. If any ratings are

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assigned to the Series A Preferred Stock in the future or if we issue other securities with a rating, such ratings, if they are lower than market expectations or are subsequently lowered or withdrawn, could adversely affect the market for or the market value of the Series A Preferred Stock. Ratings only reflect the views of the issuing rating agency or agencies and such ratings could at any time be revised downward or withdrawn entirely at the discretion of the issuing rating agency. A rating is not a recommendation to purchase, sell or hold any particular security, including the Series A Preferred Stock. Ratings do not reflect market prices or suitability of a security for a particular investor and any future rating of the Series A Preferred Stock may not reflect all risks related to us and our business, or the structure or market value of the Series A Preferred Stock.

We cannot guarantee that our Repurchase Program will enhance shareholder value and purchases, if any, could increase the volatility of the price of our Series A Preferred Stock.

Our Board of Directors has authorized the Repurchase Program, which permits us to purchase our Series A Preferred Stock through December 31, 2020. The Repurchase Program does not obligate us to purchase a specific dollar amount or number of shares of Series A Preferred Stock. The specific timing and amount of purchases, if any, will depend upon several factors, including ongoing assessments of capital needs, the market price of the Series A Preferred Stock, and other factors, including general market conditions. There can be no assurance that we will make future purchases of Series A Preferred Stock or that we will purchase a sufficient number of shares to satisfy market expectations.

Purchases of our Series A Preferred Stock could affect the market price and increase volatility of our Series A Preferred Stock. We cannot provide any assurance that purchases under the Repurchase Program will be made at the best possible price. Additionally, purchases under our Repurchase Program could diminish our cash reserves or increase borrowings under our Senior Credit Facility or Subordinated Facility, which may impact our ability to finance future growth and to pursue possible future strategic opportunities and acquisitions. Although our Repurchase Program is intended to enhance long-term shareholder value, there is no assurance that it will do so.

We are permitted to and could discontinue our Repurchase Program prior to its expiration or completion. The existence of the Repurchase Program could cause our Series A Preferred Stock price to be higher than it would be in the absence of such a program, and any such discontinuation could cause the market price of our Series A Preferred Stock to decline.

The Change of Control Conversion Right may make it more difficult for a party to acquire us or discourage a party from acquiring us.

The Change of Control Conversion Right of the Series A Preferred Stock provided in the Certificate of Designation may have the effect of discouraging a third party from making an acquisition proposal for us or of delaying, deferring or preventing certain of our change of control transactions under circumstances that otherwise could provide the holders of our Series A Preferred Stock with the opportunity to realize a premium over the then-current market price of such equity securities or that stockholders may otherwise believe is in their best interests.

Changes in the method of determining the London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest rates under our Senior Credit Facility and the floating dividend rate of our Series A Preferred Stock.

LIBOR is a basic rate of interest widely used as a global reference for setting interest rates on loans and payment rates on other financial instruments. Our Senior Credit Facility uses LIBOR as the reference rate for Eurodollar denominated borrowings. In addition, on and after April 15, 2022, dividends on the Series A Preferred Stock accrue at a floating rate equal to the sum of: (a) Three-Month LIBOR Rate as calculated on each applicable determination date, plus (b) 6.578%.

In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. It is unclear if LIBOR will cease to exist at that time, if new methods of calculating LIBOR will be established such that it continues to exist after 2021 or whether different reference rates

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will develop. It is impossible to predict the effect these developments, any discontinuance, modification or other reforms to LIBOR or the establishment of alternative reference rates may have on LIBOR, other benchmark rates or floating rate debt instruments.

Although our Senior Credit Facility and Series A Preferred Stock contain LIBOR alternative provisions and the use of alternative reference rates, new methods of calculating LIBOR or other reforms could cause the interest rates under our Senior Credit Facility or the dividend rate on our Series A Preferred Stock to be materially different than expected, which could have an adverse effect on our business, financial position, and results of operations, and our ability to pay dividends on the Series A Preferred Stock and Class A common stock.

If we are unable to redeem the Series A Preferred Stock on or after April 15, 2022, a substantial increase in the Three-Month LIBOR Rate or an alternative rate could negatively impact our ability to pay dividends on the Series A Preferred Stock and Class A common stock.

If we do not repurchase or redeem our Series A Preferred Stock on or after April 15, 2022, a substantial increase in the Three-Month LIBOR Rate (if it then exists), or a substantial increase in the alternative reference rate, could negatively impact our ability to pay dividends on the Series A Preferred Stock. An increase in the dividends payable on our Series A Preferred Stock would negatively impact dividends on our Class A common stock. We cannot assure you that we will have adequate sources of capital to repurchase or redeem the Series A Preferred Stock on or after April 15, 2022. If we are unable to repurchase or redeem the Series A Preferred Stock and our ability to pay dividends on the Series A Preferred Stock and Class A common stock is negatively impacted, the market value of the Series A Preferred Stock and Class A common stock could be materially adversely impacted.

We may not have sufficient earnings and profits in order for dividends on the Series A Preferred Stock to be treated as dividends for U.S. federal income tax purposes.

The dividends payable by us on the Series A Preferred Stock may exceed our current and accumulated earnings and profits, as calculated for U.S. federal income tax purposes. If this occurs, it will result in the amount of the dividends that exceed such earnings and profits being treated for U.S. federal income tax purposes first as a return of capital to the extent of the beneficial owner’s adjusted tax basis in the Series A Preferred Stock, and the excess, if any, over such adjusted tax basis as gain from the sale or exchange of property, which generally results in capital gain. Such treatment will generally be unfavorable for corporate beneficial owners and may also be unfavorable to certain other beneficial owners.

You may be subject to tax if we make or fail to make certain adjustments to the conversion rate of the Series A Preferred Stock even though you do not receive a corresponding cash dividend.

The Conversion Rate as defined in the Certificate of Designation for the Series A Preferred Stock is subject to adjustment in certain circumstances. A failure to adjust (or to adjust adequately) the Conversion Rate after an event that increases your proportionate interest in us could be treated as a deemed taxable dividend to you. If you are a non-U.S. holder, any deemed dividend may be subject to U.S. federal withholding tax at a 30% rate, or such lower rate as may be specified by an applicable treaty, which may be set off against subsequent payments on the Series A Preferred Stock. In April 2016, the Internal Revenue Service issued new proposed income tax regulations in regard to the taxability of changes in conversion rights that will apply to the Series A Preferred Stock when published in final form and may be applied to us before final publication in certain instances.

We are a “controlled company” under NASDAQ Global Select Market rules, and as such we are entitled to an exemption from certain corporate governance standards of the NASDAQ Global Select Market, and you may not have the same protections afforded to shareholders of companies that are subject to all of the NASDAQ Global Market corporate governance requirements.

We qualify as a “controlled company” within the meaning of NASDAQ Global Select Market corporate governance standards because an affiliated holder controls more than 50% of our voting power. Under NASDAQ Global Select

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Market rules, a company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” and may elect not to comply with certain corporate governance requirements.

Although our board of directors has established a nominating and corporate governance committee and a compensation committee of independent directors, it may determine to eliminate these committees at any time. If these committees were eliminated, you may not have the same protections afforded to shareholders of companies that are subject to all of NASDAQ Global Select Market corporate governance requirements.

Item 1B. Unresolved Staff Comments

None.

Item 3. Legal Proceedings

We are the subject of lawsuits and claims arising in the ordinary course of business from time to time. Management cannot predict the ultimate outcome of such lawsuits and claims. While the lawsuits and claims are asserted for amounts that may be material, should an unfavorable outcome occur, management does not currently expect that any currently pending matters will have a material adverse effect on our financial position or results of operations except as described in Part II, Item 8 “Financial Statements and Supplementary Data,” Note 14 "Commitments and Contingencies" to the audited consolidated financial statements, which are incorporated herein by reference.

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our Class A common stock is traded on the NASDAQ Global Select Market under the symbol “SPKE." There is no public market for our Class B common stock. On March 3, 2020, we had one holder of record of our Class A common stock and two holders of record of our Class B common stock, excluding stockholders for whom shares are held in “nominee” or “street name.”

Dividends

We typically pay a cash dividend each quarter to holders of our Class A common stock to the extent we have cash available for distribution and are permitted to do so under the terms of our Senior Credit Facility.

Recent Sales of Unregistered Equity Securities

We have not sold any unregistered equity securities other than as previously reported.

Purchases of Equity Securities

The following table sets forth information regarding purchases of our Series A Preferred Stock by us during the three months ended December 31, 2019 pursuant to our Repurchase Program.

Period	(a) Total Number of Shares Purchased		(b) Average Price Paid per Share			(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)		(d) Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs (1)
October 1 - October 31, 2019	2,300		$	24.94		2,300		—
November 1 - November 30, 2019	23,138		24.82			23,138		—
December 1 - December 31, 2019	—		—			—		—
Total	25,438		$	24.83		25,438		—

(1) On May 22, 2019, the Company announced that the Board of Directors authorized the Repurchase Program to purchase shares of Series A Preferred Stock through May 20, 2020. On November 8, 2019, the Repurchase Program was amended and extended through December 31, 2020. There is no dollar limit on the amount of Series A Preferred Stock that may be purchased. The Repurchase Program does not obligate us to make any repurchases and may be suspended for periods or discontinued at any time.

Stock Performance Graph

The following graph compares the quarterly performance of our Class A common stock to the NASDAQ Composite Index ("NASDAQ Composite") and the Dow Jones U.S. Utilities Index ("IDU"). The chart assumes that the value of the investment in our Class A common stock and each index was $100 at December 31, 2014 and that all dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance.

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The performance graph above and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act or the Exchange Act, except to the extent that we specifically incorporate it by reference.

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Item 6. Selected Financial Data

The following table sets forth selected historical financial information for each of the years in the five year period ended December 31, 2019. The information as of and for the years ended December 31, 2019, 2018 and 2017 is derived from the consolidated financial statements contained in this Form 10-K and should be read in conjunction with the information contained in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Financial Statements and Supplementary Data.” Financial information as of and for the years ended December 31, 2016 and 2015 was derived from information filed as part of our 2018 and 2017 Form 10-Ks.

(in thousands, except per share and volumetric data)		Year Ended December 31,
		2019				2018				2017				2016				2015
Income Statement Data:
Total revenues		$	813,725			$	1,005,928			$	798,055			$	546,697			$	358,153
Operating income (loss)		23,979				(3,654		)		102,420				84,001				29,905
Net income (loss)		14,213				(14,392		)		75,044				65,673				25,975
Net income (loss) attributable to Non-Controlling Interests		5,763				(13,206		)		55,799				51,229				22,110
Net income (loss) attributable to Spark Energy, Inc. stockholders		8,450				(1,186		)		19,245				14,444				3,865
Net income (loss) attributable to stockholders of Class A common stock		359				(9,295		)		16,207				14,444				3,865
Net income (loss) attributable to Spark Energy, Inc. per share of Class A common stock
Basic		$	0.03			$	(0.69	)		$	1.23			$	1.27			$	0.63
Diluted		$	0.02			$	(0.69	)		$	1.21			$	1.11			$	0.53
Weighted average common shares outstanding
Basic		14,286				13,390				13,143				11,402				6,129
Diluted		14,568				13,390				13,346				12,690				6,655
Balance Sheet Data:
Current assets		$	236,128			$	291,980			$	296,738			$	197,983			$	102,680
Current liabilities		$	141,955			$	141,951			$	151,027			$	184,056			$	84,188
Total assets		$	422,968			$	488,738			$	503,741			$	367,749			$	162,234
Long-term liabilities		$	123,712			$	165,735			$	152,446			$	67,438			$	44,727
Cash Flow Data:
Cash flows provided by operating activities		$	91,735			$	59,763			$	62,131			$	66,950			$	45,931
Cash flows provided by (used in) investing activities		$	1,398			$	(18,981	)		$	(77,558	)		$	(33,489	)		$	(41,943	)
Cash flows (used in) provided by financing activities		$	(85,103	)		$	(20,563	)		$	25,886			$	(18,975	)		$	(3,873	)
Other Financial Data:
Adjusted EBITDA (1)		$	92,404			$	70,716			$	102,884			$	81,892			$	36,869
Retail gross margin (1)		$	220,740			$	185,109			$	224,509			$	182,369			$	113,615
Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders		$	(45,176	)		$	(45,261	)		$	(43,319	)		$	(43,297	)		$	(20,043	)
Other Operating Data:
RCEs (thousands)		672				908				1,042				774				415
Electricity volumes (MWh)		6,416,568				8,630,653				6,755,663				4,170,593				2,075,479
Natural gas volumes (MMBtu)		14,543,563				16,778,393				18,203,684				16,819,713				14,786,681

(1) Adjusted EBITDA and retail gross margin are non-GAAP financial measures. For a definition and reconciliation of each of Adjusted EBITDA and retail gross margin to their most directly comparable financial measures calculated and presented in accordance with GAAP, please see “Management's Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Performance Measures.”

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the consolidated financial statements and the related notes thereto included elsewhere in this Annual Report. In this Annual Report, the terms “Spark Energy,” “Company,” “we,” “us” and “our” refer collectively to Spark Energy, Inc. and its subsidiaries.

Overview

We are an independent retail energy services company founded in 1999 that provides residential and commercial customers in competitive markets across the United States with an alternative choice for natural gas and electricity. We purchase our natural gas and electricity supply from a variety of wholesale providers and bill our customers monthly for the delivery of natural gas and electricity based on their consumption at either a fixed or variable price. Natural gas and electricity are then distributed to our customers by local regulated utility companies through their existing infrastructure. As of December 31, 2019, we operated in 94 utility service territories across 19 states and the District of Columbia.

Our business consists of two operating segments:

•

Retail Electricity Segment. In this segment, we purchase electricity supply through physical and financial transactions with market counterparties and ISOs and supply electricity to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the years ended December 31, 2019, 2018 and 2017, approximately 85%, 86% and 82%, respectively, of our retail revenues were derived from the sale of electricity.

•

Retail Natural Gas Segment. In this segment, we purchase natural gas supply through physical and financial transactions with market counterparties and supply natural gas to residential and commercial consumers pursuant to fixed-price and variable-price contracts. For the years ended December 31, 2019, 2018 and 2017, approximately 15%, 14% and 18%, respectively, of our retail revenues were derived from the sale of natural gas.

Recent Developments

Preferred Stock Repurchase Program

In November 2019, we amended and extended our repurchase program (the "Repurchase Program") of our Series A Preferred Stock. The Repurchase Program allows us to purchase Series A Preferred Stock through December 31, 2020, at prevailing prices, in open market or negotiated transactions, subject to market conditions, maximum share prices and other considerations. The Repurchase Program does not obligate us to make any repurchases and may be suspended at any time.

Drivers of Our Business

The success of our business and our profitability are impacted by a number of drivers, the most significant of which are discussed below.

Customer Growth

Customer growth is a key driver of our operations. Our ability to acquire customers organically or by acquisition is important to our success as we experience ongoing customer attrition. Our customer growth strategy includes growing organically through traditional sales channels complemented by customer portfolio and business acquisitions.

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We measure our number of customers using residential customer equivalents ("RCEs"). The following table shows our RCEs by segment as of December 31, 2019, 2018 and 2017:

RCEs:
	December 31,
(In thousands)	2019	2018	2017
Retail Electricity	533	754	868
Retail Natural Gas	139	154	174
Total Retail	672	908	1,042

The following table details our count of RCEs by geographical location as of December 31, 2019:

RCEs by Geographic Location:
(In thousands)	Electricity	% of Total	Natural Gas	% of Total	Total	% of Total
New England	217	41%	27	20%	244	36%
Mid-Atlantic	196	37%	49	35%	245	36%
Midwest	57	10%	42	30%	99	15%
Southwest	63	12%	21	15%	84	13%
Total	533	100%	139	100%	672	100%

The geographical locations noted above include the following states:

•	New England - Connecticut, Maine, Massachusetts and New Hampshire;

•	Mid-Atlantic - Delaware, Maryland (including the District of Columbia), New Jersey, New York and Pennsylvania;

•	Midwest - Illinois, Indiana, Michigan and Ohio; and

•	Southwest - Arizona, California, Colorado, Florida, Nevada and Texas.

Across our market areas, we have operated under a number of different retail brands. We currently operate under seven retail brands. During 2019 and 2018, we consolidated our brands and billings systems in an effort to simplify our business operations. Our goal is to reduce the number of separate brands to three by the end of 2020.

Organic Sales

Our organic sales strategies are designed to offer competitive pricing, price certainty, and/or green product offerings to residential and commercial customers. We manage growth on a market-by-market basis by developing price curves in each of the markets we serve and comparing the market prices to the price offered by the local regulated utility. We then determine if there is an opportunity in a particular market based on our ability to create a competitive product on economic terms that provides customer value and satisfies our profitability objectives. We develop marketing campaigns using a combination of sales channels. Our marketing team continuously evaluates the effectiveness of each customer acquisition channel and makes adjustments in order to achieve desired targets. During the year ended December 31, 2019, we added approximately 214,000 RCEs through our various organic sales channels.

Acquisitions

We acquire companies and portfolios of customers through both external and affiliated channels. In 2017, we acquired approximately 206,000 RCEs through acquisitions of Verde Energy USA Holdings, LLC ("Verde

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Energy"), Perigee Energy, LLC ("Perigee Energy"), and a customer portfolio. In 2018, we added approximately 81,000 RCEs through our acquisitions of HIKO, a customer portfolio from an affiliate, and a customer portfolio from Starion Energy ("Starion"). In 2019, we added approximately 33,000 RCEs as part of the completion of the acquisition from Starion.

Our ability to realize returns from acquisitions that are acceptable to us is dependent on our ability to successfully identify, negotiate, finance and integrate acquisitions.

RCE Activity

The following table shows our RCE activity during the years ended December 31, 2019, 2018 and 2017.

(In thousands)	Retail Electricity	Retail Natural Gas	Total	% Net Annual Increase (Decrease)
December 31, 2016	571	203	774
Additions	659	61	720
Attrition	(362)	(90)	(452)
December 31, 2017	868	174	1,042	35%
Additions	363	69	432
Attrition	(477)	(89)	(566)
December 31, 2018	754	154	908	(13)%
Additions	189	58	247
Attrition	(410)	(73)	(483)
December 31, 2019	533	139	672	(26)%

The increase of our RCE counts in 2017 was related to the acquisition of customers and businesses in excess of natural customer attrition. In 2018 and 2019, our attrition exceeded customer adds due to our intentional non-renewal of certain larger C&I customer contracts, lower organic sales spending, and fewer acquisitions and slightly higher attrition impacted by our brand consolidation activities. Average monthly attrition rates during 2019, 2018 and 2017 were as follows:

	Year Ended	Quarter Ended
	December 31	December 31	September 30	June 30	March 31
2017	4.3%	4.9%	4.2%	4.1%	3.8%
2018	4.7%	6.7%	4.0%	3.7%	4.2%
2019	5.0%	7.0%	4.0%	3.8%	5.4%

Customer attrition occurs primarily as a result of: (i) customer initiated switches; (ii) residential moves (iii) disconnection resulting from customer payment defaults and (iv) pro-active non-renewal of contracts. Customer attrition during the year ended December 31, 2019 was slightly higher than the prior year due to a previously communicated strategy to shrink our C&I customer book, resulting in our pro-active non-renewal of some of our lower-margin large commercial contracts.

Customer Acquisition Costs

Managing customer acquisition costs is a key component of our profitability. Customer acquisition costs are those costs related to obtaining customers organically and do not include the cost of acquiring customers through acquisitions, which are recorded as customer relationships. For each of the three years ended December 31, 2019, customer acquisition costs were as follows:

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	Year Ended December 31,
(In thousands)	2019			2018			2017
Customer Acquisition Costs	$	18,685		$	13,673		$	25,874

We strive to maintain a disciplined approach to recovery of our customer acquisition costs within a 12 month period. We capitalize and amortize our customer acquisition costs over a two year period, which is based on our estimate of the expected average length of a customer relationship. We factor in the recovery of customer acquisition costs in determining which markets we enter and the pricing of our products in those markets. Accordingly, our results are significantly influenced by our customer acquisition costs. Changes in customer acquisition costs from period to period reflect our focus on growing organically versus growth through acquisitions. We are currently focused on growing through organic sales channels; however, we continue to evaluate opportunities to acquire customers through acquisitions and pursue such acquisitions when it makes sense economically or strategically for the Company.

Customer Credit Risk

Approximately 67% of our revenues are derived from customers in utilities where customer credit risk is borne by the utility in exchange for a discount on amounts billed. Where we have customer credit risk, we record bad debt based on an estimate of uncollectible amounts. Our bad debt expense on non-POR revenues was as follows:

	Year Ended December 31,
	2019		2018		2017
Total Non-POR Bad Debt as Percent of Revenue	3.3	%	2.6	%	2.5	%

During the year ended December 31, 2019, we experienced higher bad debt expense versus 2018 primarily due to an increase in residential customers in non-POR markets. In addition, as our geographic and acquisition channel mix has changed, our bad debt expense has increased. In order to manage this exposure in 2019, we have increased our focus on: collection efforts, timely billing, and credit monitoring for new enrollments in non-POR markets. During the year ended December 31, 2018, we experienced higher bad debt expense versus 2017 primarily as a result of our brand consolidations.

For the years ended December 31, 2019, 2018 and 2017, approximately 67%, 66% and 66%, respectively, of our retail revenues were collected through POR programs where substantially all of our credit risk was with local regulated utility companies. As of December 31, 2019, 2018 and 2017, all of these local regulated utility companies had investment grade ratings. During these same periods, we paid these local regulated utilities a weighted average discount of approximately 0.8%, 1.0% and 1.1%, respectively, of total revenues for customer credit risk protection.

Weather Conditions

Weather conditions directly influence the demand for natural gas and electricity and affect the prices of energy commodities. Our hedging strategy is based on forecasted customer energy usage, which can vary substantially as a result of weather patterns deviating from historical norms. We are particularly sensitive to this variability in our residential customer segment where energy usage is highly sensitive to weather conditions that impact heating and cooling demand.

Our risk management policies direct that we hedge substantially all of our forecasted demand, which is typically hedged to long-term normal weather patterns. We also attempt to add additional protection through hedging from time to time to protect us from potential volatility in markets where we have historically experienced higher exposure to extreme weather conditions. Because we attempt to match commodity purchases to anticipated demand, unanticipated changes in weather patterns can have a significant impact on our operating results and cash flows from period to period.

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We experienced milder than normal weather in most of our geographies for most of 2019 with the exception of the third quarter. This milder weather resulted in lower sales volumes during the period and lower demand for commodities. In markets where we were fully hedged, we were selling back some of those hedges into a depressed wholesale market. During the first quarter of 2019, we experienced weather volatility in the New England, Mid-Atlantic and Midwest regions that resulted in higher-than-normal heating degree days. On average, the first quarter of 2019 turned out to be milder than normal, however prices in the day-ahead and real-time markets during this time were less volatile than they had been in the first quarter of 2018, which in aggregate positively affected our gross margin.

During the third quarter of 2019, we experienced warmer than normal weather across many of our markets, which increased demand for electricity from our customer base. In anticipation of increased demand and volatility in ERCOT ("Electric Reliability Council of Texas"), and as an additional form of insurance, we purchased additional power to mitigate the volatility observed in late August and early September of 2019. These factors had a positive impact on our electricity unit margins in the third quarter of 2019.

Asset Optimization

Our asset optimization opportunities primarily arise during the winter heating season when demand for natural gas is typically at its highest. Given the opportunistic nature of these activities and because we account for these activities using the mark to market method of accounting, we experience variability in our earnings from our asset optimization activities from year to year.

Net asset optimization resulted in a gain of $2.8 million, a gain of $4.5 million and a loss of $0.7 million for the years ended December 31, 2019, 2018 and 2017, respectively.

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Non-GAAP Performance Measures

We use the Non-GAAP performance measures of Adjusted EBITDA and Retail Gross Margin to evaluate and measure our operating results. These measures for the three years ended December 31, 2019 were as follows:

	Year Ended December 31,
(in thousands)	2019				2018				2017
Adjusted EBITDA	$	92,404			$	70,716			$	102,884
Retail Gross Margin	$	220,740			$	185,109			$	224,509

Adjusted EBITDA. We define “Adjusted EBITDA” as EBITDA less (i) customer acquisition costs incurred in the current period, plus or minus (ii) net gain (loss) on derivative instruments, and (iii) net current period cash settlements on derivative instruments, plus (iv) non-cash compensation expense, and (v) other non-cash and non-recurring operating items. EBITDA is defined as net income (loss) before the provision for income taxes, interest expense and depreciation and amortization.

We deduct all current period customer acquisition costs (representing spending for organic customer acquisitions) in the Adjusted EBITDA calculation because such costs reflect a cash outlay in the period in which they are incurred, even though we capitalize and amortize such costs over two years. We do not deduct the cost of customer acquisitions through acquisitions of businesses or portfolios of customers in calculating Adjusted EBITDA.

We deduct our net gains (losses) on derivative instruments, excluding current period cash settlements, from the Adjusted EBITDA calculation in order to remove the non-cash impact of net gains and losses on these instruments. We also deduct non-cash compensation expense that results from the issuance of restricted stock units under our long-term incentive plan due to the non-cash nature of the expense. Finally, we also adjust from time to time other non-cash or unusual and/or infrequent charges due to either their non-cash nature or their infrequency.

We believe that the presentation of Adjusted EBITDA provides information useful to investors in assessing our liquidity and financial condition and results of operations and that Adjusted EBITDA is also useful to investors as a financial indicator of our ability to incur and service debt, pay dividends and fund capital expenditures. Adjusted EBITDA is a supplemental financial measure that management and external users of our consolidated financial statements, such as industry analysts, investors, commercial banks and rating agencies, use to assess the following:

 

•	our operating performance as compared to other publicly traded companies in the retail energy industry, without regard to financing methods, capital structure or historical cost basis;

•	the ability of our assets to generate earnings sufficient to support our proposed cash dividends;

•	our ability to fund capital expenditures (including customer acquisition costs) and incur and service debt; and

•	our compliance with financial debt covenants. (Refer to Note 10 "Debt" in the Company’s audited consolidated financial statements for discussion of the material terms of our Senior Credit Facility, including the covenant requirements for our Minimum Fixed Charge Coverage Ratio, Maximum Total Leverage Ratio, and Maximum Senior Secured Leverage Ratio.)

The GAAP measures most directly comparable to Adjusted EBITDA are net income (loss) and net cash provided by (used in) operating activities. The following table presents a reconciliation of Adjusted EBITDA to these GAAP measures for each of the periods indicated.

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	Year Ended December 31,
(in thousands)	2019				2018				2017
Reconciliation of Adjusted EBITDA to Net Income (Loss):
Net income (loss)	$	14,213			$	(14,392	)		$	75,044
Depreciation and amortization	40,987				52,658				42,341
Interest expense	8,621				9,410				11,134
Income tax expense	7,257				2,077				38,765
EBITDA	71,078				49,753				167,284
Less:
Net, (Losses) gains on derivative instruments	(67,749		)		(18,170		)		5,008
Net, Cash settlements on derivative instruments	42,820				(10,587		)		16,309
Customer acquisition costs	18,685				13,673				25,874
Plus:
Non-cash compensation expense	5,487				5,879				5,058
Non-recurring legal and regulatory settlements	14,457				—				—
Gain on disposal of eRex	(4,862		)		—				—
Change in Tax Receivable Agreement liability (1)	—				—				(22,267		)
Adjusted EBITDA	$	92,404			$	70,716			$	102,884

(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 13 "Income Taxes."

The following table presents a reconciliation of Adjusted EBITDA to net cash provided by operating activities for each of the periods indicated.

	Year Ended December 31,
(in thousands)	2019				2018				2017
Reconciliation of Adjusted EBITDA to net cash provided by operating activities:
Net cash provided by operating activities	$	91,735			$	59,763			$	62,131
Amortization of deferred financing costs	(1,275		)		(1,291		)		(1,035		)
Bad debt expense	(13,532		)		(10,135		)		(6,550		)
Interest expense	8,621				9,410				11,134
Income tax expense	7,257				2,077				38,765
Change in Tax Receivable Agreement liability (1)	—				—				(22,267		)
Changes in operating working capital
Accounts receivable, prepaids, current assets	(33,475		)		10,482				31,905
Inventory	(924		)		(674		)		718
Accounts payable and accrued liabilities	11,534				(5,093		)		(13,672		)
Other	22,463				6,177				1,755
Adjusted EBITDA	$	92,404			$	70,716			$	102,884
Cash Flow Data:
Cash flows provided by operating activities	$	91,735			$	59,763			$	62,131
Cash flows provided by (used in) investing activities	$	1,398			$	(18,981	)		$	(77,558	)
Cash flows (used in) provided by financing activities	$	(85,103	)		$	(20,563	)		$	25,886

(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 13 "Income Taxes."

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Retail Gross Margin. We define retail gross margin as operating income (loss) plus (i) depreciation and amortization expenses and (ii) general and administrative expenses, less (iii) net asset optimization revenues (expenses), (iv) net gains (losses) on non-trading derivative instruments, and (v) net current period cash settlements on non-trading derivative instruments. Retail gross margin is included as a supplemental disclosure because it is a primary performance measure used by our management to determine the performance of our retail natural gas and electricity segments. As an indicator of our retail energy business’s operating performance, retail gross margin should not be considered an alternative to, or more meaningful than, operating income (loss), its most directly comparable financial measure calculated and presented in accordance with GAAP.

We believe retail gross margin provides information useful to investors as an indicator of our retail energy business's operating performance.

The GAAP measure most directly comparable to Retail Gross Margin is operating income (loss). The following table presents a reconciliation of Retail Gross Margin to operating income (loss) for each of the periods indicated.

	Year Ended December 31,
(in thousands)	2019				2018				2017
Reconciliation of Retail Gross Margin to Operating Income (Loss):
Operating income (loss)	$	23,979			$	(3,654	)		$	102,420
Plus:
Depreciation and amortization	40,987				52,658				42,341
General and administrative expense	133,534				111,431				101,127
Less:
Net asset optimization revenue (expense)	2,771				4,511				(717		)
(Losses) gains on non-trading derivative instruments	(67,955		)		(19,571		)		5,588
Cash settlements on non-trading derivative instruments	42,944				(9,614		)		16,508
Retail Gross Margin	$	220,740			$	185,109			$	224,509
Retail Gross Margin - Retail Electricity Segment	$	160,540			$	124,668			$	158,468
Retail Gross Margin - Retail Natural Gas Segment	$	60,200			$	60,441			$	66,041

Our non-GAAP financial measures of Adjusted EBITDA and Retail Gross Margin should not be considered as alternatives to net income (loss), net cash provided by operating activities, or operating income (loss). Adjusted EBITDA and Retail Gross Margin are not presentations made in accordance with GAAP and have limitations as analytical tools. You should not consider Adjusted EBITDA or Retail Gross Margin in isolation or as a substitute for analysis of our results as reported under GAAP. Because Adjusted EBITDA and Retail Gross Margin exclude some, but not all, items that affect net income (loss), net cash provided by operating activities, and operating income (loss), and are defined differently by different companies in our industry, our definition of Adjusted EBITDA and Retail Gross Margin may not be comparable to similarly titled measures of other companies.

Management compensates for the limitations of Adjusted EBITDA and Retail Gross Margin as analytical tools by reviewing the comparable GAAP measures, understanding the differences between the measures and incorporating these data points into management’s decision-making process.

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Consolidated Results of Operations

(In Thousands)	Year Ended December 31,
	2019				2018				2017
Revenues:
Retail revenues	$	810,954			$	1,001,417			$	798,772
Net asset optimization revenues (expenses)	2,771				4,511				(717		)
Total Revenues	813,725				1,005,928				798,055
Operating Expenses:
Retail cost of revenues	615,225				845,493				552,167
General and administrative expense	133,534				111,431				101,127
Depreciation and amortization	40,987				52,658				42,341
Total Operating Expenses	789,746				1,009,582				695,635
Operating income (loss)	23,979				(3,654		)		102,420
Other (expense)/income:
Interest expense	(8,621		)		(9,410		)		(11,134		)
Change in Tax Receivable Agreement liability (1)	—				—				22,267
Gain on disposal of eRex	4,862				—				—
Total other income/(expense)	1,250				749				256
Total other (expenses)/income	(2,509		)		(8,661		)		11,389
Income (loss) before income tax expense	21,470				(12,315		)		113,809
Income tax expense	7,257				2,077				38,765
Net income (loss)	$	14,213			$	(14,392	)		$	75,044
Other Performance Metrics:
Adjusted EBITDA (2)	$	92,404			$	70,716			$	102,884
Retail Gross Margin (2)	220,740				185,109				224,509
Customer Acquisition Costs	18,685				13,673				25,874
RCE Attrition	5.0		%		4.7		%		4.3		%
Distributions paid to Class B non-controlling unit holders and dividends paid to Class A common shareholders	$	(45,176	)		$	(45,261	)		$	(43,319	)

(1) Represents the change in the value of the Tax Receivable Agreement liability due to U.S. Tax Reform. See discussion in Note 13 "Income Taxes."

(2) Adjusted EBITDA and Retail Gross Margin are non-GAAP financial measures. See “—Non-GAAP Performance Measures” for a reconciliation of Adjusted EBITDA and Retail Gross Margin to their most directly comparable GAAP financial measures.

Total Revenues. Total revenues for the year ended December 31, 2019 were approximately $813.7 million, a decrease of approximately $192.2 million, or 19%, from approximately $1,005.9 million for the year ended December 31, 2018. This decrease was primarily due to a decrease in electricity and natural gas volumes as a result of a smaller C&I customer book in 2019 as compared to 2018, partially offset by an increase in electricity unit revenue per MWh. Total revenues for the year ended December 31, 2018 increased approximately $207.8 million, or 26%, from approximately $798.1 million for the year ended December 31, 2017. This increase was primarily due to an increase in electricity volumes driven by the acquisitions of the HIKO and two customer portfolios, full year results from the Verde Companies, and higher-than-normal electricity and natural gas pricing in 2018, partially offset by a decrease in natural gas volumes due to warmer-than-normal weather in the second and third quarters of 2018.

Analysis of the impact of changes in prices and volumes between the years ended December 31, 2019, 2018 and 2017 are as follows:

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	2019 vs. 2018				2018 vs. 2017
Change in electricity volumes sold	$	(221.5	)		$	182.5
Change in natural gas volumes sold	(18.4		)		(11.1		)
Change in electricity unit revenue per MWh	46.5				23.4
Change in natural gas unit revenue per MMBtu	2.9				7.9
Change in net asset optimization (expense) revenue	(1.7		)		5.1
Change in total revenues	$	(192.2	)		$	207.8

Retail Cost of Revenues. Total retail cost of revenues for the year ended December 31, 2019 was approximately $615.2 million, a decrease of approximately $230.3 million, or 27%, from approximately $845.5 million for the year ended December 31, 2018. This decrease was primarily due to a decrease in electricity and natural gas volumes as a result of a smaller C&I customer book in 2019, a decrease in electricity and natural gas unit cost, and a change in fair value of our retail derivative portfolio. Total retail cost of revenues for the year ended December 31, 2018 increased approximately $293.3 million, or 53%, from approximately $552.2 million for the year ended December 31, 2017. This increase was primarily due to an increase in electricity volumes driven by the acquisitions of HIKO and two customer portfolios, full year results from the Verde Companies, higher-than-normal electricity and natural gas prices due to the extreme unpredictable weather in the first quarter of 2018, increased capacity costs in the second and third quarters of 2018, and additional hedges in ERCOT in the third quarter of 2018.

Analysis of the impact of changes in prices and volumes between the years ended December 31, 2019, 2018, and 2017 are as follows:

	2019 vs. 2018				2018 vs. 2017
Change in electricity volumes sold	$	(189.5	)		$	138.5
Change in natural gas volumes sold	(10.3		)		(5.9		)
Change in electricity unit cost per MWh	(21.4		)		101.2
Change in natural gas unit cost per MMBtu	(4.9		)		8.2
Change in value of retail derivative portfolio	(4.2		)		51.3
Change in retail cost of revenues	$	(230.3	)		$	293.3

General and Administrative Expense. General and administrative expense for the year ended December 31, 2019 was approximately $133.5 million, an increase of approximately $22.1 million, or 20%, as compared to $111.4 million for the year ended December 31, 2018. This increase was primarily attributable to non-recurring legal and regulatory settlements and increased litigation expense in 2019. General and administrative expense for the year ended December 31, 2018 increased approximately $10.3 million or 10%, as compared to $101.1 million for the year ended December 31, 2017. This increase was primarily attributable to reductions in the fair value of earnout liabilities, which decreased general and administrative expenses in 2017 to a greater extent than in 2018, increased commissions paid to commercial brokers, and variable costs associated with increased RCEs from our acquisitions.

Depreciation and Amortization Expense. Depreciation and amortization expense for the year ended December 31, 2019 was approximately $41.0 million, a decrease of approximately $11.7 million, or 22%, from approximately $52.7 million for the year ended December 31, 2018. This decrease was primarily due to the decreased amortization expense associated with customer relationship intangibles. Depreciation and amortization expense for the year ended December 31, 2018 increased approximately $10.4 million, or 24%, from approximately $42.3 million for the year ended December 31, 2017. This increase was primarily due to the increased amortization expense associated with customer relationship intangibles from the acquisitions of the Verde Companies, HIKO and customers from an affiliate, and the write-off of assets no longer in use as a result of integration activities.

Customer Acquisition Cost. Customer acquisition cost for the year ended December 31, 2019 was approximately $18.7 million, an increase of approximately $5.0 million, or 37% from approximately $13.7 million for the year ended December 31, 2018. This increase was primarily due to an increase in the number of organic sales in 2019 as

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compared to 2018, as we had slowed our organic sales in 2018 to concentrate on acquisitions of companies and portfolios of customers. Customer acquisition cost for the year ended December 31, 2018 decreased approximately $12.2 million, or 47% from approximately $25.9 million for the year ended December 31, 2017. This decrease was primarily due to a decrease in the number of organic sales in 2018 as we were more focused on acquisitions of businesses, customer portfolio additions, and integration.

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Operating Segment Results 

	Year Ended December 31,
	2019				2018				2017
	(in thousands, except volume and per unit operating data)
Retail Electricity Segment
Total Revenues	$	688,451			$	863,451			$	657,566
Retail Cost of Revenues	552,250				762,771				477,012
Less: Net (Losses) Gains on non-trading derivatives, net of cash settlements	(24,339		)		(23,988		)		22,086
Retail Gross Margin (1) —Electricity	$	160,540			$	124,668			$	158,468
Volumes—Electricity (MWhs)	6,416,568				8,630,653				6,755,663
Retail Gross Margin (2) —Electricity per MWh	$	25.02			$	14.44			$	23.46
Retail Natural Gas Segment
Total Revenues	$	122,503			$	137,966			$	141,206
Retail Cost of Revenues	62,975				82,722				75,155
Less: Net (Losses) Gains on non-trading derivatives, net of cash settlements	(672		)		(5,197		)		10
Retail Gross Margin (1) —Gas	$	60,200			$	60,441			$	66,041
Volumes—Gas (MMBtus)	14,543,563				16,778,393				18,203,684
Retail Gross Margin (2) —Gas per MMBtu	$	4.14			$	3.60			$	3.63

(1) Reflects the Retail Gross Margin attributable to our Retail Electricity Segment or Retail Natural Gas Segment, as applicable. Retail Gross Margin is a non-GAAP financial measure. See “—Non-GAAP Performance Measures” for a reconciliation of Retail Gross Margin to most directly comparable financial measures presented in accordance with GAAP.

(2) Reflects the Retail Gross Margin for the Retail Electricity Segment or Retail Natural Gas Segment, as applicable, divided by the total volumes in MWh or MMBtu, respectively.

Retail Electricity Segment

Total revenues for the Retail Electricity Segment for the year ended December 31, 2019 were approximately $688.5 million, a decrease of approximately $175.0 million, or 20%, from approximately $863.5 million for the year ended December 31, 2018. This decrease was largely due to lower volumes sold, resulting in a decrease of $221.5 million as a result of a smaller C&I customer book in 2019. This decrease was partially offset by higher weighted average electricity rates, due to our customer mix shifting away from large C&I customers, which resulted in an increase of $46.5 million. Total revenues for the Retail Electricity Segment for the year ended December 31, 2018 increased approximately $205.9 million, or 31%, from approximately $657.6 million for the year ended December 31, 2017. This increase was largely due to an increase in volumes, a result of our acquisitions of HIKO and two customer portfolios, full year results from the Verde Companies, a larger C&I customer book in 2018, extreme cold weather in the first quarter of 2018, and warmer than normal weather in the second and third quarters of 2018, resulting in an increase of $182.5 million. This increase was further impacted by the higher electricity pricing environment, which resulted in an increase of $23.4 million.

Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2019 was approximately $552.3 million, a decrease of approximately $210.5 million, or 28%, from approximately $762.8 million for the year ended December 31, 2018. This decrease was primarily due to a decrease in volumes, resulting in a decrease of $189.5 million. This decrease was further impacted by decreased electricity supply costs, which resulted in a decrease in retail cost of revenues of $21.4 million. Additionally, there was an increase of $0.4 million due to a change in the value of our retail derivative portfolio used in hedging. Retail cost of revenues for the Retail Electricity Segment for the year ended December 31, 2018 increased approximately $285.8 million, or 60%, from approximately $477.0 million for the year ended December 31, 2017. This increase was primarily due to an increase in volumes as a result of the acquisitions of HIKO and two customers portfolios, full year results from the Verde

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Companies, a larger C&I customer book in 2018, extreme cold weather in the first quarter of 2018, and warmer than normal weather in second and third quarter of 2018, resulting in an increase of $138.5 million. This increase was further impacted by increased electricity prices, REC requirements and capacity costs, which resulted in an increase in retail cost of revenues of $101.2 million. Additionally, there was an increase of $46.1 million due to a change in the value of our retail derivative portfolio used in hedging.

Retail gross margin for the Retail Electricity Segment for the year ended December 31, 2019 increased approximately $35.8 million, or 29%, as compared to the year ended December 31, 2018, and 2018 decreased approximately $33.8 million or 21% as compared to December 31, 2017 as indicated in the table below (in millions).

	2019 vs. 2018				2018 vs. 2017
Change in volumes sold	$	(32.0	)		$	44.0
Change in unit margin per MWh	67.8				(77.8		)
Change in retail electricity segment retail gross margin	$	35.8			$	(33.8	)

Unit margins were positively impacted in 2019 compared to prior year primarily as a result of the higher volumes from our residential customers, which tend to have higher unit margins than our C&I customers. Unit margins were negatively impacted in 2018 compared to prior year primarily as a result of higher volumes from our C&I customers.

The volumes of electricity sold decreased from 8,630,653 MWh for the year ended December 31, 2018 to 6,416,568 MWh for the year ended December 31, 2019. This decrease was primarily due to a smaller C&I customer book in 2019. The volumes of electricity sold increased from 6,755,663 MWh for the year ended December 31, 2017 to 8,630,653 MWh for the year ended December 31, 2018. This increase was primarily due to our acquisitions of HIKO and two customer portfolios, full year results from the Verde Companies, a larger C&I customer book in 2018, extreme cold weather in the first quarter of 2018, and warmer than normal weather in the second and third quarters of 2018.

Retail Natural Gas Segment

Total revenues for the Retail Natural Gas Segment for the year ended December 31, 2019 were approximately $122.5 million, a decrease of approximately $15.5 million, or 11%, from approximately $138.0 million for the year ended December 31, 2018. This decrease was primarily attributable to a decrease in volumes of $18.4 million, offset by higher rates, which resulted in an increase in total revenues of $2.9 million. Total revenues for the Retail Natural Gas Segment for the year ended December 31, 2018 decreased by approximately $3.2 million, or 2%, from approximately $141.2 million for the year ended December 31, 2017. This decrease was primarily attributable to an increase in price of $7.9 million, offset by a decrease in customer sales volume, which decreased total revenues by $11.1 million.

Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2019 were approximately $63.0 million, a decrease of approximately $19.7 million, or 24%, from approximately $82.7 million for the year ended December 31, 2018. This decrease was primarily due to decreased supply costs of $4.9 million, a decrease of $10.3 million related to decreased volumes, and a decrease of $4.5 million due to change in the fair value of our retail derivative portfolio used for hedging. Retail cost of revenues for the Retail Natural Gas Segment for the year ended December 31, 2018 increased approximately $7.5 million, or 10%, from approximately $75.2 million for the year ended December 31, 2017. This increase was due to increased supply costs of $8.2 million, $5.2 million change in the fair value of our retail derivative portfolio used for hedging, offset by $5.9 million related to decreased volumes.

Retail gross margin for the Retail Natural Gas Segment for the year ended December 31, 2019 decreased by approximately $0.2 million, or less than 1% from approximately $60.4 million for the year ended December 31,

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2018, and 2018 decreased approximately $5.6 million or 8% from approximately $66.0 million for the year ended December 31, 2017 as indicated in the table below (in millions).

	2019 vs. 2018				2018 vs. 2017
Change in volumes sold	$	(8.1	)		$	(5.2	)
Change in unit margin per MMBtu	7.9				(0.4		)
Change in retail natural gas segment retail gross margin	$	(0.2	)		$	(5.6	)

Unit margins were positively impacted in 2019 compared to prior year as a result of higher volumes from our residential customers, which tend to have higher unit margins than our C&I customers. Unit margins were negatively impacted in 2018 compared to prior year primarily as a result of higher volume from our C&I customers.

The volumes of natural gas sold decreased from 16,778,393 MMBtu for the year ended December 31, 2018 to 14,543,563 MMBtu for the year ended December 31, 2019. This decrease was primarily due to warmer-than-normal weather in the second and third quarters of 2019. The volumes of natural gas sold decreased from 18,203,684 MMBtu for the year ended December 31, 2017 to 16,778,393 MMBtu for the year ended December 31, 2018. This decrease was primarily due to warmer-than-normal weather in the second and third quarters of 2018.

Liquidity and Capital Resources

Overview

Our primary sources of liquidity are cash generated from operations and borrowings under our Senior Credit Facility. Our principal liquidity requirements are to meet our financial commitments, finance current operations, fund organic growth and/or acquisitions, service debt and pay dividends. Our liquidity requirements fluctuate with our level of customer acquisition costs, acquisitions, collateral posting requirements on our derivative instruments portfolio, distributions, the effects of the timing between the settlement of payables and receivables, including the effect of bad debts, weather conditions, and our general working capital needs for ongoing operations. We believe that cash generated from operations and our available liquidity sources will be sufficient to sustain current operations and to pay required taxes and quarterly cash distributions, including the quarterly dividends to the holders of the Class A common stock and the Series A Preferred Stock, for the next twelve months. Estimating our liquidity requirements is highly dependent on then-current market conditions, including weather events, forward prices for natural gas and electricity, market volatility and our then existing capital structure and requirements.

We believe that the financing of any additional growth through acquisitions and/or the need for more liquidity in the first half of 2020 may require further equity or debt financing and/or further expansion of our Senior Credit Facility.

Liquidity Position

The following table details our available liquidity as of December 31, 2019:

	December 31,
($ in thousands)	2019
Cash and cash equivalents	$	56,664
Senior Credit Facility Availability (1)	57,068
Subordinated Debt Facility Availability (2)	25,000
Total Liquidity	$	138,732

(1) Reflects amount of Letters of Credit that could be issued based on existing covenants as of December 31, 2019.

(2) The availability of the Subordinated Facility is dependent on our Founder's willingness and ability to lend. See "—Sources of Liquidity—Subordinated Debt Facility."

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Borrowings and related posting of letters of credit under our Senior Credit Facility are subject to material variations on a seasonal basis due to the timing of commodity purchases to satisfy natural gas inventory requirements and to meet customer demands during periods of peak usage. Additionally, borrowings are subject to borrowing base and covenant restrictions.

Cash Flows

Our cash flows were as follows for the respective periods (in thousands):

	Year Ended December 31,
	2019				2018				2017
Net cash provided by operating activities	$	91,735			$	59,763			$	62,131
Net cash provided by (used in) investing activities	$	1,398			$	(18,981	)		$	(77,558	)
Net cash (used in) provided by financing activities	$	(85,103	)		$	(20,563	)		$	25,886

Cash Flows Provided by Operating Activities. Cash flows provided by operating activities for the year ended December 31, 2019 increased by $32.0 million compared to the year ended December 31, 2018. The increase was primarily the result of a higher net income in 2019 coupled with a decrease in the changes in working capital for the year ended December 31, 2019. Cash flows provided by operating activities for the year ended December 31, 2018 decreased by $2.4 million compared to the year ended December 31, 2017. The decrease was primarily the result of a decrease in the changes in working capital for the year ended December 31, 2018 and the impact of extreme weather events during the first quarter of 2018.

Cash Flows Provided by Investing Activities. Cash flows provided by investing activities increased by $20.4 million for the year ended December 31, 2019. The increase was primarily the result of a reduction in the amount of cash paid for acquisitions during the year ended December 31, 2019 compared to the year ended December 31, 2018, and proceeds received from the sale of the Company's equity method investment in 2019. Cash flows used in investing activities decreased by $58.6 million for the year ended December 31, 2018. The decrease was primarily the result of the $81.3 million acquisition of the Verde Companies, Perigee and other customers during the year ended December 31, 2017, offset by the acquisition of HIKO of $14.3 million during the year ended December 31, 2018.

Cash Flows Used in Financing Activities. Cash flows used in financing activities increased by $64.5 million for the year ended December 31, 2019. The increase in cash flows used in financing activities was primarily due to increased net paydown of our Senior Credit Facility and subordinated debt, as well as payments to settle the Company's Tax Receivable Agreement liability. In addition, for the year ended December 31, 2018, we received proceeds from the issuance of Series A Preferred Stock of approximately $48.5 million, which did not reoccur during 2019. Cash flows used in financing activities increased by $46.4 million for the year ended December 31, 2018. The increase in cash flows used in financing activities was primarily due to increased net paydown of our Senior Credit Facility, additional dividends paid to holders of Series A Preferred Stock, payments related to the Verde Promissory Note and payments associated with the acquisition of customers from an affiliate for the year ended December 31, 2018.

Sources of Liquidity and Capital Resources

Senior Credit Facility

As of December 31, 2019, we had total commitments of $217.5 million, of which $160.4 million was outstanding, including $37.4 million of outstanding letters of credit. In January 2019, our total commitments under our Senior Credit Facility increased to $217.5 million. Under the Senior Credit Facility, we have various limits on advances for Working Capital Loans, Letters of Credit and Bridge Loans. The Senior Credit Facility matures on May 19, 2021. For a description of the terms and conditions of our Senior Credit Facility, including descriptions of the interest rate, commitment fee, covenants and terms of default, please see Note 10 "Debt" in the notes to our

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consolidated financial statements. As of December 31, 2019, we were in compliance with the covenants under our Senior Credit Facility.

Amended and Restated Subordinated Debt Facility

 

Our Subordinated Debt Facility allows us to draw advances in increments of no less than $1.0 million per advance up to $25.0 million. Although we may use the Subordinated Debt Facility from time to time to enhance short term liquidity, we do not view the Subordinated Debt Facility as a material source of liquidity. See Note 10 "Debt" for additional details. As of December 31, 2019, there was zero outstanding borrowings under the Subordinated Debt Facility.

Uses of Liquidity and Capital Resources

Repayment of Current Portion of Senior Credit Facility

Our Senior Credit Facility matures in 2021, and thus, no amounts are due currently. However, due to the revolving nature of the facility, excess cash available is generally used to reduce the balance outstanding, which at December 31, 2019 was $123.0 million. The current variable interest rate on the facility at December 31, 2019 was 4.71%.

Customer Acquisitions

Our customer acquisition strategy consists of customer growth obtained through organic customer additions as well as opportunistic acquisitions. During the years ended December 31, 2019 and 2018, we spent a total of $18.7 million and $13.7 million, respectively, on organic customer acquisitions. Our ability to grow our customer base organically or by acquisition is important to our success as we experience ongoing customer attrition each period.

Capital Expenditures

Our capital requirements each year are relatively low and generally consist of minor purchases of equipment or information system upgrades and improvements. Capital expenditures for the year ended December 31, 2019 included approximately $1.1 million related to information systems improvements.

Dividends and Distributions

For the year ended December 31, 2019, we paid dividends to holders of our Class A common stock of $0.725 per share or $10.4 million in the aggregate. In order to pay our stated dividends to holders of our Class A common stock, our subsidiary, Spark HoldCo is required to make corresponding distributions to holders of Class B common stock (our non-controlling interest holders). As a result, during the year ended December 31, 2019, Spark HoldCo made distributions of $15.1 million to our non-controlling interest holders related to the dividend payments to our Class A shareholders.

For the year ended December 31, 2019, we paid $8.1 million of dividends to holders of our Series A Preferred Stock, and as of December 31, 2019, we had accrued $2.0 million related to dividends to holders of our Series A Preferred Stock, which we paid on January 15, 2020. For the year ended December 31, 2019, we declared dividends of $2.1875 per share or $8.1 million in the aggregate on our Series A Preferred Stock.

On January 21, 2020, our Board of Directors declared a quarterly cash dividend in the amount of $0.18125 per share to holders of our Class A common stock and $0.546875 per share for the Series A Preferred Stock. Dividends on Class A common stock will be paid on March 16, 2020 to holders of record on March 2, 2020 and Series A Preferred Stock dividends will be paid on April 15, 2020 to holders of record on April 1, 2020.

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Our ability to pay dividends in the future will depend on many factors, including the performance of our business and restrictions under our Senior Credit Facility. If our business does not generate sufficient cash for Spark HoldCo to make distributions to us to fund our Class A common stock and Series A Preferred Stock dividends, we may have to borrow to pay such amounts. Further, even if our business generates cash in excess of our current annual dividend (of $0.725 per share on our Class A common stock), we may reinvest such excess cash flows in our business and not increase the dividends payable to holders of our Class A common stock. Our future dividend policy is within the discretion of our Board of Directors and will depend upon the results of our operations, our financial condition, capital requirements and investment opportunities.

Verde Promissory Note

In January 2018, we issued an amended and restated promissory note to the sellers of the Verde Companies (the "Verde Promissory Note"). As of December 31, 2018, there was $1.0 million outstanding under the Verde Promissory Note, all of which was paid in January 2019. The note bore interest at 9% per annum, and we made monthly payments of principal and associated interest, a portion of which was deposited into an escrow account to provide security for certain indemnification claims and obligations under the Verde purchase agreement. As of December 31, 2019 and 2018, a total of $5.3 million and $7.6 million was held in escrow for such claims.

Verde Earnout Termination Note

In January 2018, we issued a promissory note in the principal amount of $5.9 million in connection with an agreement to terminate the earnout obligation arising in connection with our acquisition of the Verde Companies (the "Verde Earnout Termination Note"). The Verde Earnout Termination Note matured in June 2019 and bore interest at a rate of 9% per annum. Under the terms of the Verde Earnout Termination Note, we were permitted to withhold amounts otherwise due at maturity related to certain indemnifiable matters. A payment of $1.0 million was made to the seller of the Verde Companies in June 2019, and $4.9 million was withheld (the “Verde Holdback”) to be applied to indemnifiable matters. As of December 31, 2019 and 2018, there was zero and $5.9 million outstanding under the Verde Earnout Termination Note, respectively.

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Table of Contents

Summary of Contractual Obligations

The following table discloses aggregate information about our contractual obligations and commercial commitments as of December 31, 2019 (in millions): 

	Total			2020			2021			2022			2023			2024			> 5 years
Purchase obligations:
Pipeline transportation agreements	$	6.6		$	0.9		$	1.5		$	0.7		$	0.7		$	0.7		$	2.1
Other purchase obligations (1)	9.4			6.1			2.8			0.5			—			—			—
Total purchase obligations	$	16.0		$	7.0		$	4.3		$	1.2		$	0.7		$	0.7		$	2.1
Senior Credit Facility	$	123.0		$	—		$